Valaris Limited (VAL) 10-Q 2010 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

     Washington, D.C. 20549     

FORM 10-Q

(Mark One)

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended June 30, 2010

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to

Commission File Number 1-8097

Ensco plc

(Exact name of registrant as specified in its charter)

England and Wales (State or other jurisdiction of incorporation or organization)   6 Chesterfield Gardens London, England (Address of principal executive offices) 98-0635229 (I.R.S. Employer Identification No.)   W1J 5BQ (Zip Code)

Registrant's telephone number, including area code:  44 (0) 20 7659 4660

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes ý        No  o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes ý        No  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer ý Non-accelerated filero  (Do not check if a smaller reporting company) Accelerated filer Smaller reporting company o o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   Yes  o      No  ý

As of July 21, 2010, there were 142,959,478 American depositary shares of the registrant issued and outstanding, each representing one Class A ordinary share.

ENSCO PLC

INDEX TO FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2010

PART I       FINANCIAL INFORMATION
ITEM 1.   FINANCIAL STATEMENTS	3
Report of Independent Registered Public Accounting Firm	3
Condensed Consolidated Statements of Income      Three Months Ended June 30, 2010 and 2009	4
Condensed Consolidated Statements of Income      Six Months Ended June 30, 2010 and 2009	5
Condensed Consolidated Balance Sheets      June 30, 2010 and December 31, 2009	6
Condensed Consolidated Statements of Cash Flows Six Months Ended June 30, 2010 and 2009	7
Notes to Condensed Consolidated Financial Statements	8
ITEM 2.   MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION      AND RESULTS OF OPERATIONS	26
ITEM 3.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	45
ITEM 4.   CONTROLS AND PROCEDURES	45
PART II       OTHER INFORMATION
ITEM 1.   LEGAL PROCEEDINGS	46
ITEM 1A. RISK FACTORS	49
ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	52
ITEM 6.    EXHIBITS	53
SIGNATURES	54

FORWARD-LOOKING STATEMENTS

 This report contains forward-looking statements that are subject to a number of risks and uncertainties and are based on information as of the date of this report. We assume no obligation to update these statements based on information after the date of this report.

 Forward-looking statements include words or phrases such as "anticipate," "believe," "estimate," "expect," "intend," "plan," "project," "could," "may," "might," "should," "will" and words and phrases of similar import. The forward-looking statements include, but are not limited to, statements about the impact of the December 2009 reorganization of the Company's corporate structure (referred to elsewhere herein as the "redomestication") and our plans, objectives, expectations and intentions with respect the reto and with respect to future operations, including the tax savings or other benefits that we expect to achieve as a result of the redomestication. Forward-looking statements also include statements regarding future operations, market conditions, cash generation, the impact of the BP Macondo well incident in the U.S. Gulf of Mexico, anticipated commencement of the ENSCO 8502 drilling contract, contributions from our ultra-deepwater semisubmersible rig fleet expansion program, expense management, industry trends or conditions and the overall business environment; statements regarding future levels of, or trends in, utilization, day rates, revenues, operating expenses, contract term, contract backlog, capital expenditures, insurance, financing and funding; statements regarding future rig construction (including construction in progress and completion thereof), enhancement, upgrade or repair and timing thereof; statements regarding future delivery, mobilization, contract commencement, relocation or other movement of rigs and timing thereof; statements regarding future availability or suitability of rigs and the timing thereof; and statements regarding the likely outcome of litigation, legal proceedings, investigations or insurance or other claims and the timing thereof.

Forward-looking statements are made pursuant to safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Numerous factors could cause actual results to differ materially from those in the forward-looking statements, including:

• changes in U.S. or non-U.S. laws, including tax laws, that could effectively reduce or eliminate the benefits we expect to achieve from our December 2009 redomestication or regulatory or legislative activity that would impact U.S. Gulf of Mexico operations, potentially resulting in a force majeure situation,  

• an inability to realize expected benefits from the redomestication,  

• costs related to the redomestication and ancillary matters, which could be greater than expected,  

• the impact of the BP Macondo well incident in the U.S. Gulf of Mexico upon future deepwater and other offshore drilling operations in general, and as respects current and future deepwater drilling permit and operations moratoria/suspensions, new and future legislative, regulatory or permit requirements (including requirements related to equipment and operations), future lease sales and other governmental activities that may impact deepwater and other offshore operations in the U.S. Gulf of Mexico in general, and our existing drilling contracts for ENSCO 8500, ENSCO 8501, ENSCO 8502, ENSCO 8503 and our U.S. Gulf of Mexico jackup rigs in particular,  

• industry conditions and competition, including changes in rig supply and demand or new technology, 

• risks associated with the global economy and its impact on capital markets and liquidity,  

• prices of oil and natural gas and their impact upon future levels of drilling activity and expenditures,  

• further declines in drilling activity, which may cause us to idle or stack additional rigs,  

• excess rig availability or supply resulting from delivery of newbuild drilling rigs,  

• concentration of our rig fleet in premium jackups,  

• concentration of our active ultra-deepwater semisubmersible drilling rigs in the U.S. Gulf of Mexico,

• cyclical nature of the industry,  

• worldwide expenditures for oil and natural gas drilling,  

• the ultimate resolution of the ENSCO 69 situation in general and the pending litigation, potential return of the rig or package policy political risk insurance recovery in particular,  

• changes in the timing of revenue recognition resulting from the deferral of certain revenues for mobilization of our drilling rigs, time waiting on weather or time in shipyards, which are recognized over the contract term upon commencement of drilling operations,

1

• operational risks, including excessive unplanned downtime due to rig or equipment failure, damage or repair in general and hazards created by severe storms and hurricanes in particular,  

• changes in the dates our rigs will enter a shipyard, be delivered, return to service or enter service,  

• risks inherent to shipyard rig construction, repair or enhancement, including risks associated with concentration of our ENSCO 8500 Series® rig construction contracts in a single shipyard in Singapore, unexpected delays in equipment delivery and engineering or design issues following shipyard delivery,  

• changes in the dates new contracts actually commence,  

• renegotiation, nullification, cancellation or breach of contracts or letters of intent with customers or other parties, including failure to negotiate definitive contracts following announcements or receipt of letters of intent,  

• risks associated with offshore rig operations or rig relocations,  

• inability to collect receivables,  

• availability of transport vessels to relocate rigs,  

• environmental or other liabilities, risks or losses, whether related to hurricane damage, losses or liabilities (including wreckage or debris removal) in the Gulf of Mexico or otherwise, that may arise in the future which are not covered by insurance or indemnity in whole or in part,  

• limited availability or high cost of insurance coverage for certain perils such as hurricanes in the Gulf of Mexico or associated removal of wreckage or debris,  

• self-imposed or regulatory limitations on drilling locations in the Gulf of Mexico during hurricane season,  

• impact of current and future government laws and regulation affecting the oil and gas industry in general and our operations in particular, including taxation, as well as repeal or modification of same,  

• our ability to attract and retain skilled personnel,  

•   governmental action and political and economic uncertainties, which may result in expropriation, nationalization, confiscation or deprivation of our assets or create a force majeure situation,  

• terrorism or military action impacting our operations, assets or financial performance,  

• outcome of litigation, legal proceedings, investigations or insurance or other claims,

• adverse changes in foreign currency exchange rates, including their impact on the fair value measurement of our derivative instruments,

• potential long-lived asset or goodwill impairments,

• potential reduction in fair value of our auction rate securities and the ultimate resolution of our pending arbitration proceedings.

 Moreover, the United States Congress, the Internal Revenue Service, the United Kingdom Parliament or Her Majesty's Revenue and Customs may enact new statutory or regulatory provisions that could adversely affect our status as a non-U.S. corporation or otherwise adversely affect our anticipated consolidated effective income tax rate. Retroactive statutory or regulatory actions have occurred in the past, and there can be no assurance that any such provisions, if enacted or promulgated, would not have retroactive application.

 In addition to the numerous factors described above and in "Item 2.   Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part I and "Item 1A. Risk Factors" in Part II of this report, you should carefully read and consider "Item 1A.   Risk Factors" in Part I and  "Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II of our Annual Report on Form  10-K for the year ended December 31, 2009, as updated in the Current Report on Form 8-K dated June 8, 2010.

2

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders

Ensco plc:

We have reviewed the condensed consolidated balance sheet of Ensco plc and subsidiaries as of June 30, 2010, the related condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2010 and 2009, and the related condensed consolidated statements of cash flows for the six-month periods ended June 30, 2010 and 2009. These condensed consolidated financial statements are the responsibility of the Company's management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the condensed consolidated financial statements referred to above for them to be in conformity with U.S. generally accepted accounting principles.

We have previously audited, in accordance with standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Ensco plc and subsidiaries as of December 31, 2009, and the related consolidated statements of income and cash flows for the year then ended (not presented herein); and in our report dated February 25, 2010 except for the updated disclosures and reclassification of ENSCO 50 and ENSCO 51 operating results from continuing to discontinued operations for all periods presented, as described in Note 11, as to which the date is June 8, 2010, we expressed an unqualified opinion on these consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2009, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ KPMG LLP

Dallas, Texas

July 22, 2010

3

ENSCO PLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In millions, except per share amounts)

(Unaudited)

	Three Months Ended            June 30,
	2010			2009
OPERATING REVENUES		$406.3			$497.3
OPERATING EXPENSES
Contract drilling (exclusive of depreciation)		207.0			171.2
Depreciation		52.8			45.8
General and administrative		22.0			16.0
		281.8			233.0
OPERATING INCOME		124.5			264.3
OTHER INCOME, NET		12.8			6.9
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		137.3			271.2
PROVISION FOR INCOME TAXES
Current income tax expense		26.3			38.2
Deferred income tax expense		(6.7	)		11.3
		19.6			49.5
INCOME FROM CONTINUING OPERATIONS		117.7			221.7
DISCONTINUED OPERATIONS
Income (loss) from discontinued operations, net		4.5			(8.5	)
Gain (loss) on disposal of discontinued operations, net		5.7			(11.8	)
		10.2			(20.3	)
NET INCOME		127.9			201.4
NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS		(1.6	)		(1.1	)
NET INCOME ATTRIBUTABLE TO ENSCO		$126.3			$200.3
EARNINGS (LOSS) PER SHARE - BASIC
Continuing operations		$  0.82			$  1.55
Discontinued operations		.07			(.14	)
		$  0.89			$  1.41
EARNINGS (LOSS) PER SHARE - DILUTED
Continuing operations		$  0.82			$  1.55
Discontinued operations		.07			(.14	)
		$  0.89			$  1.41
NET INCOME ATTRIBUTABLE TO ENSCO SHARES
Basic		$124.8			$197.9
Diluted		$124.8			$197.9
WEIGHTED-AVERAGE SHARES OUTSTANDING
Basic		140.9			140.3
Diluted		140.9			140.4
CASH DIVIDENDS PER SHARE		$   .35			$  .025

The accompanying notes are an integral part of these condensed consolidated financial statements.

4

ENSCO PLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In millions, except per share amounts)

(Unaudited)

	Six Months Ended            June 30,
	2010			2009
OPERATING REVENUES		$847.8			$981.5
OPERATING EXPENSES
Contract drilling (exclusive of depreciation)		389.8			325.8
Depreciation		105.5			89.6
General and administrative		42.6			28.0
		537.9			443.4
OPERATING INCOME		309.9			538.1
OTHER INCOME, NET		15.9			2.6
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		325.8			540.7
PROVISION FOR INCOME TAXES
Current income tax expense		47.1			85.4
Deferred income tax expense		4.3			18.3
		51.4			103.7
INCOME FROM CONTINUING OPERATIONS		274.4			437.0
DISCONTINUED OPERATIONS
Income (loss) from discontinued operations, net		10.2			(1.7	)
Gain (loss) on disposal of discontinued operations, net		34.9			(11.8	)
		45.1			(13.5	)
NET INCOME		319.5			423.5
NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS		(3.4	)		(2.5	)
NET INCOME ATTRIBUTABLE TO ENSCO		$316.1			$421.0
EARNINGS (LOSS) PER SHARE - BASIC
Continuing operations		$  1.90			$  3.06
Discontinued operations		.32			(.09	)
		$  2.22			$  2.97
EARNINGS (LOSS) PER SHARE - DILUTED
Continuing operations		$  1.90			$  3.06
Discontinued operations		.32			(.09	)
		$  2.22			$  2.97
NET INCOME ATTRIBUTABLE TO ENSCO SHARES
Basic		$312.2			$415.9
Diluted		$312.2			$415.9
WEIGHTED-AVERAGE SHARES OUTSTANDING
Basic		140.8			140.2
Diluted		140.9			140.2
CASH DIVIDENDS PER SHARE		$  .375			$   .05

The accompanying notes are an integral part of these condensed consolidated financial statements.

5

ENSCO PLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions, except share and par value amounts)

	June 30,      2010		December 31,        2009
	(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$1,237.1		$1,141.4
Accounts receivable, net	302.7		324.6
Other	147.8		186.8
Total current assets	1,687.6		1,652.8
PROPERTY AND EQUIPMENT, AT COST	6,227.3		6,151.2
Less accumulated depreciation	1,622.5		1,673.9
Property and equipment, net	4,604.8		4,477.3
GOODWILL	336.2		336.2
LONG-TERM INVESTMENTS	45.2		60.5
OTHER ASSETS, NET	247.2		220.4
	$6,921.0		$6,747.2
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable - trade	$   152.5		$   159.1
Accrued liabilities and other	246.7		308.6
Current maturities of long-term debt	17.2		17.2
Total current liabilities	416.4		484.9
LONG-TERM DEBT	248.6		257.2
DEFERRED INCOME TAXES	365.1		377.3
OTHER LIABILITIES	117.2		120.7
COMMITMENTS AND CONTINGENCIES
ENSCO SHAREHOLDERS' EQUITY
Class A ordinary shares, U.S. $.10 par value, 250.0 million shares          authorized, 150.0 million shares issued	15.0		15.0
Class B ordinary shares, £1 par value, 50,000 shares authorized and issued	.1		.1
Additional paid-in capital	618.1		602.6
Retained earnings	5,141.7		4,879.2
Accumulated other comprehensive income	.7		5.2
Treasury shares, at cost, 7.1 million shares and 7.5 million shares	(8.0	)	(2.9	)
Total Ensco shareholders' equity	5,767.6		5,499.2
NONCONTROLLING INTERESTS	6.1		7.9
Total equity	5,773.7		5,507.1
	$6,921.0		$6,747.2

The accompanying notes are an integral part of these condensed consolidated financial statements.

6

ENSCO PLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)

	Six Months Ended                 June 30,
	2010		2009
OPERATING ACTIVITIES
Net income	$ 319.5		$ 423.5
Adjustments to reconcile net income to net cash provided by operating
activities of continuing operations:
Depreciation expense	105.5		89.6
Share-based compensation expense	22.4		17.0
Amortization expense	16.0		15.7
Loss on asset impairment	12.2		--
Deferred income tax expense	4.3		18.3
(Income) loss from discontinued operations, net	(10.2	)	1.7
(Gain) loss on disposal of discontinued operations, net	(34.9	)	11.8
Other	5.5		1.5
Changes in operating assets and liabilities:
Decrease in accounts receivable	5.8		35.7
Increase in other assets	(.1	)	(49.5	)
Decrease in liabilities	(102.4	)	(.8	)
Net cash provided by operating activities of continuing operations	343.6		564.5
INVESTING ACTIVITIES
Additions to property and equipment	(336.6	)	(469.1	)
Proceeds from disposal of discontinued operations	132.4		4.9
Proceeds from disposition of assets	.7		1.6
Net cash used in investing activities	(203.5	)	(462.6	)
FINANCING ACTIVITIES
Cash dividends paid	(53.6	)	(7.1	)
Reduction of long-term borrowings	(8.6	)	(8.6	)
Financing costs	(6.2	)	--
Repurchase of shares	(5.1	)	(4.0	)
Other	(7.3	)	1.3
Net cash used in financing activities	(80.8	)	(18.4	)
Effect of exchange rate changes on cash and cash equivalents	(.7	)	.1
Net cash provided by operating activities of discontinued operations	37.1		8.8
INCREASE IN CASH AND CASH EQUIVALENTS	95.7		92.4
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	1,141.4		789.6
CASH AND CASH EQUIVALENTS, END OF PERIOD	$1,237.1		$ 882.0

The accompanying notes are an integral part of these condensed consolidated financial statements.

7

ENSCO PLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 - Unaudited Condensed Consolidated Financial Statements

 We prepared the accompanying condensed consolidated financial statements of Ensco plc and subsidiaries (the "Company", "Ensco", "we" or "us") in accordance with accounting principles generally accepted in the United States of America ("GAAP"), pursuant to the rules and regulations of the Securities and Exchange Commission (the "SEC") included in the instructions to Form 10-Q and Article 10 of Regulation S-X. The financial information included in this report is unaudited but, in our opinion, includes all adjustments (consisting of normal recurring adjustments) that are necessary for a fair presentation of our financial positi on, results of operations and cash flows for the interim periods presented. The December 31, 2009 condensed consolidated balance sheet data were derived from our 2009 audited consolidated financial statements, as updated in the Current Report on Form 8-K dated June 8, 2010, but do not include all disclosures required by GAAP. Certain previously reported amounts have been reclassified to conform to the current year presentation. The preparation of our condensed consolidated financial statements requires management to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities, the related revenues and expenses and disclosures of gain and loss contingencies as of the date of the financial statements. Actual results could differ from those estimates.

 The financial data for the three-month and six-month periods ended June 30, 2010 and 2009 included herein have been subjected to a limited review by KPMG LLP, our independent registered public accounting firm. The accompanying independent registered public accounting firm's review report is not a report within the meaning of Sections 7 and 11 of the Securities Act of 1933, and the independent registered public accounting firm's liability under Section 11 does not extend to it.

 Results of operations for the three-month and six-month periods ended June 30, 2010 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2010.  It is recommended that these condensed consolidated financial statements be read in conjunction with our audited consolidated financial statements and notes thereto for the year ended December 31, 2009 included in our Annual Report on Form 10-K filed with the SEC on February 25, 2010, as updated in the Current Report on Form 8-K dated June 8, 2010.

Note 2 - Noncontrolling Interests

 Noncontrolling interests are classified as equity on our consolidated balance sheets, and net income attributable to noncontrolling interests is presented separately on our consolidated statements of income. In our Asia Pacific operating segment, local third parties hold a noncontrolling ownership interest in three of our subsidiaries. No changes in the ownership interests of these subsidiaries occurred during the three-month and six-month periods ended June 30, 2010 and 2009.

8

 The following table is a reconciliation of income from continuing operations attributable to Ensco for the three-month and six-month periods ended June 30, 2010 and 2009 (in millions):

	Three Months Ended              June 30,				Six Months Ended            June 30,
	2010		2009		2010		2009
Income from continuing operations	$117.7		$221.7		$274.4		$437.0
Income from continuing operations attributable to noncontrolling interests	(1.6	)	(.9	)	(3.2	)	(2.1	)
Income from continuing operations attributable to Ensco	$116.1		$220.8		$271.2		$434.9

 The following table is a reconciliation of income (loss) from discontinued operations, net, attributable to Ensco for the three-month and six-month periods ended June 30, 2010 and 2009 (in millions):

	Three Months Ended            June 30,			Six Months Ended           June 30,
	2010	2009		2010		2009
Income (loss) from discontinued operations	$10.2	$(20.3	)	$45.1		$(13.5	)
Income from discontinued operations attributable to    noncontrolling interests	--	(.2	)	(.2	)	(.4	)
Income (loss) from discontinued operations attributable to Ensco	$10.2	$(20.5	)	$44.9		$(13.9	)

Note 3 - Earnings Per Share

 We compute basic and diluted earnings per share ("EPS") in accordance with the two-class method. Net income attributable to Ensco used in our computations of basic and diluted EPS is adjusted to exclude net income allocated to non-vested shares granted to our employees and non-employee directors. Weighted-average shares outstanding used in our computation of diluted EPS includes the dilutive effect of share options using the treasury stock method and excludes non-vested shares.

 The following table is a reconciliation of net income attributable to Ensco shares used in our basic and diluted EPS computations for the three-month and six-month periods ended June 30, 2010 and 2009 (in millions):

	Three Months Ended             June 30,				Six Months Ended             June 30,
	2010		2009		2010		2009
Net income attributable to Ensco	$126.3		$200.3		$316.1		$421.0
Net income allocated to non-vested share awards	(1.5	)	(2.4	)	(3.9	)	(5.1	)
Net income attributable to Ensco shares	$124.8		$197.9		$312.2		$415.9

 The following table is a reconciliation of the weighted-average shares used in our basic and diluted EPS computations for the three-month and six-month periods ended June 30, 2010 and 2009 (in millions):

	Three Months Ended             June 30,		Six Months Ended              June 30,
	2010	2009	2010	2009
Weighted-average shares - basic	140.9	140.3	140.8	140.2
Potentially dilutive share options	.0	.1	.1	.0
Weighted-average shares - diluted	140.9	140.4	140.9	140.2

9

 Antidilutive share options totaling 1.1 million were excluded from the computation of diluted EPS for the three-month periods ended June 30, 2010 and 2009.  Antidilutive share options totaling 1.0 million and 1.3 million were excluded from the computation of diluted EPS for the six-month periods ended June 30, 2010 and 2009, respectively.

Note 4 - Derivative Instruments

 Our functional currency is the U.S. dollar. As is customary in the oil and gas industry, a majority of our revenues are denominated in U.S. dollars, however, a portion of the revenues earned and expenses incurred by some of our subsidiaries are denominated in currencies other than the U.S. dollar ("foreign currencies"). These transactions are remeasured in U.S. dollars based on a combination of both current and historical exchange rates. We use foreign currency forward contracts ("derivatives") to reduce our exposure to various market risks, primarily foreign currency exchange rate risk. We maintain a foreign currency exchange rate risk management strategy that utilizes derivatives to reduce our exposure to unanticipated fluctuations in earnings and cash flows caused by changes in foreign currency exchange rates. Although no interest rate related derivatives were outstanding as of June 30, 2010 and December 31, 2009, we occasionally employ an interest rate risk management strategy that utilizes derivatives to minimize or eliminate unanticipated fluctuations in earnings and cash flows arising from changes in, and volatility of, interest rates. We minimize our credit risk relating to the counterparties of our derivatives by transacting with multiple, high-quality financial institutions, thereby limiting exposure to individual counterparties, and by monitoring the financial condition of our counterparties. We do not enter into derivatives for trading or other speculative purposes.

��

 All derivatives were recorded on our condensed consolidated balance sheets at fair value. Accounting for the gains and losses resulting from changes in the fair value of derivatives depends on the use of the derivative and whether it qualifies for hedge accounting.  As of June 30, 2010 and December 31, 2009, our condensed consolidated balance sheets included net foreign currency derivative assets of $3.0 million and $13.2 million, respectively. See "Note 9 - Fair Value Measurements" for additional information on the fair value measurement of our derivatives.

 Derivatives recorded at fair value in our condensed consolidated balance sheets as of June 30, 2010 and December 31, 2009 consisted of the following (in millions):

	Derivative Assets		Derivative Liabilities
	June 30,                  2010	December 31,               2009	June 30,                  2010	December 31, 2009
Derivatives Designated as Hedging Instruments
Foreign currency forward contracts - current(1)	$3.5	$10.2	$3.1	$1.1
Foreign currency forward contracts - non-current(2)	3.3	3.8	--	--
	6.8	14.0	3.1	1.1
Derivatives Not Designated as Hedging Instruments
Foreign currency forward contracts - current(1)	--	.3	.7	.0
	--	.3	.7	.0
Total	$6.8	$14.3	$3.8	$1.1

(1)	Derivative assets and liabilities that have maturity dates equal to or less than twelve months from the respective balance sheet date were included in other current assets and accrued liabilities and other, respectively, on our condensed consolidated balance sheets.
(2)	Derivative assets and liabilities that have maturity dates greater than twelve months from the respective balance sheet date were included in other assets, net, and other liabilities, respectively, on our condensed consolidated balance sheets.

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We utilize derivatives designated as hedging instruments to hedge forecasted foreign currency denominated transactions ("cash flow hedges"), primarily to reduce our exposure to foreign currency exchange rate risk associated with the portion of our remaining ENSCO 8500 Series® construction obligations denominated in Singapore dollars and contract drilling expenses denominated in various other currencies. As of June 30, 2010, we had cash flow hedges outstanding to exchange an aggregate $230.3 million for various foreign currencies, including $161.5 million for Singapore dollars, $44.0 million for British pounds, $13.2 million for Australian dollars and $11.6 million for othe r currencies.

Gains and losses on derivatives designated as cash flow hedges included in our condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2010 and 2009 were as follows (in millions):

Three Months Ended June 30, 2010 and 2009

Derivatives Designated    as Cash Flow Hedges	(Loss) Gain Recognized in Other Comprehensive Income ("OCI")    (Effective Portion)		(Loss) Gain  Reclassified from Accumulated Other Comprehensive Income ("AOCI") into Income      (Effective Portion)			(Loss) Gain Recognized in Income on Derivatives (Ineffective Portion and Amount Excluded from Effectiveness Testing)(1)
	2010	2009		2010	2009		2010	2009
Interest rate lock contracts(2)	$    --	$    --		$(.2)	$  (.1)		$ --	$ --
Foreign currency forward contracts(3)	(1.6)	14.2		.4	(5.0)		(.2)	4.1
Total	$(1.6)	$14.2		$ .2	$(5.1)		$(.2)	$4.1

Six Months Ended June 30, 2010 and 2009

Derivatives Designated    as Cash Flow Hedges	Loss Recognized in OCI    (Effective Portion)		(Loss) Gain  Reclassified from AOCI into Income        (Effective Portion)			Loss Recognized in Income on Derivatives (Ineffective Portion and Amount Excluded from Effectiveness Testing)(1)
	2010	2009		2010	2009		2010	2009
Interest rate lock contracts(2)	$    --	$    --		$(.3)	$    (.3)		$ --	$    --
Foreign currency forward contracts(3)	(3.0)	(1.2)		1.8	(14.8)		(.2)	(2.4)
Total	$(3.0)	$(1.2)		$1.5	$(15.1)		$(.2)	$(2.4)

(1)	Gains and losses recognized in income for ineffectiveness and amounts excluded from effectiveness testing were included in other income, net, in our condensed consolidated statements of income.
(2)	Losses on derivatives reclassified from AOCI into income (effective portion) were included in other income, net, in our condensed consolidated statements of income.
(3)	Gains and losses on derivatives reclassified from AOCI into income (effective portion) were included in contract drilling expense in our condensed consolidated statements of income.

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 We have net assets and liabilities denominated in numerous foreign currencies and use various methods to manage our exposure to foreign currency exchange rate risk. We predominantly structure our drilling contracts in U.S. dollars which significantly reduces the portion of our cash flows and assets denominated in foreign currencies. We occasionally enter into derivatives that hedge the fair value of recognized foreign currency denominated assets or liabilities but do not designate such derivatives as hedging instruments.  In these situations, a natural hedging relationship generally exists whereby changes in the fair value of the derivatives offset changes i n the fair value of the underlying hedged items. As of June 30, 2010, we had derivatives not designated as hedging instruments outstanding to exchange an aggregate $26.7 million for various foreign currencies, including $15.7 million for Australian dollars, $4.5 million for British pounds and $6.5 million for other currencies.

 Net losses of $1.7 million and net gains of $3.2 million associated with our derivatives not designated as hedging instruments were included in other income, net, in our condensed consolidated statements of income for the three-month periods ended June 30, 2010 and 2009, respectively. Net losses of $1.1 million and net gains of $2.2 million associated with our derivatives not designated as hedging instruments were included in other income, net, in our condensed consolidated statements of income for the six-month periods ended June 30, 2010 and 2009, respectively.

 As of June 30, 2010, the estimated amount of net losses associated with derivative instruments, net of tax, that will be reclassified to earnings during the next twelve months was as follows (in millions):

Net unrealized losses to be reclassified to contract drilling expense	$1.5
Net realized losses to be reclassified to other income, net	.4
Net losses to be reclassified to earnings	$1.9

Note 5 - Accrued Liabilities and Other

 Accrued liabilities and other as of June 30, 2010 and December 31, 2009 consisted of the following (in millions):

	2010	2009
Taxes	$ 72.8	$ 97.3
Deferred revenue	66.0	89.0
Wreckage and debris removal	50.3	50.3
Personnel costs	39.5	48.6
Other	18.1	23.4
	$246.7	$308.6

Note 6 - Long-Term Debt

 On May 28, 2010, we entered into an amended and restated agreement (the "2010 Credit Facility") with a syndicate of banks that provides for a $700.0 million unsecured revolving credit facility for general corporate purposes. The 2010 Credit Facility has a four-year term, expiring in May 2014, and replaces our $350.0 million five-year credit agreement which was scheduled to mature in June 2010. Advances under the 2010 Credit Fac ility bear interest at LIBOR plus an applicable margin rate (currently 2.0% per annum), depending on our credit rating. We are required to pay an annual undrawn facility fee (currently .25% per annum) on the total $700.0 million commitment, which is also based on our credit rating. We also are required to maintain a debt to total capitalization ratio less than or equal to 50% under the 2010 Credit Facility. We have the right, subject to lender consent, to increase the commitments under the 2010 Credit Facility up to $850.0 million.  We had no amounts outstanding under the 2010 Credit Facility or the prior credit agreement as of June 30, 2010 and December 31, 2009, respectively.

Note 7 - Share-Based Compensation

During the quarter ended June 30, 2010, we granted 560,354 non-vested share awards to our employees, officers and non-employee directors for annual equity awards and for equity awards granted to new or recently promoted employees, pursuant to our 2005 Long-Term Incentive Plan ("LTIP").  Grants of non-vested share awards generally vest at a rate of 20% per year, as determined by a committee of the Board of Directors.  Non-vested share awards granted to certain officers vest at a rate of 33% per year. All non-vested share awards have voting and dividend rights e ffective on the date of grant and are measured using the market value of our shares on the date of grant. The weighted-average grant-date fair value of non-vested share awards granted during the quarter ended June 30, 2010 was $35.11 per share.  All non-vested share award grants were issued out of treasury.

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 During the quarter ended June 30, 2010, we granted 160,293 share options to certain officers as annual equity awards made pursuant to our LTIP.  The share options granted become exercisable in annual 33% increments over a three-year period and, to the extent not exercised, expire on the seventh anniversary of the date of grant. The following table summarizes the value of share options granted during the quarter ended June 30, 2010 (per share):

Weighted-average grant-date fair value	$11.05
Weighted-average exercise price	$34.45

 The exercise price of share options granted during the period equals the market value of the underlying stock on the date of grant. The fair value of each option award was estimated on the date of grant using the Black-Scholes option valuation model with the following weighted-average assumptions for the quarter ended June 30, 2010:

Risk-free interest rate	1.8	%
Expected life (in years)	4.01
Expected volatility	53.1	%
Dividend yield	4.1	%

 Expected volatility is based on the historical volatility in the market price of our shares over the period of time equivalent to the expected term of the options granted. The expected term of options granted is derived from historical exercise patterns over a period of time equivalent to the contractual term of the options granted. We have not experienced significant differences in the historical exercise patterns among officers, employees and non-employee directors for them to be considered separately for valuation purposes. The risk-free interest rate is based on the implied yield of U.S. Treasury zero-coupon issues on the date of grant with a remaining term a pproximating the expected term of the options granted.

Note 8 - Comprehensive Income

 Accumulated other comprehensive income as of June 30, 2010 and December 31, 2009 was comprised of gains and losses on derivative instruments, net of tax. The components of other comprehensive (loss) income, net of tax, for the three-month and six-month periods ended June 30, 2010 and 2009 were as follows (in millions):

	Three Months Ended              June 30,				Six Months Ended             June 30,
	2010		2009		2010		2009
Net income	$127.9		$201.4		$319.5		$423.5
Other comprehensive (loss) income:
Net change in fair value of derivatives	(1.6	)	14.2		(3.0	)	(1.2	)
Reclassification of gains and losses on derivative
instruments from other comprehensive (income) loss
into net income	(.2	)	5.1		(1.5	)	15.1
Net other comprehensive (loss) income	(1.8	)	19.3		(4.5	)	13.9
Comprehensive income	126.1		220.7		315.0		437.4
Comprehensive income attributable to noncontrolling interests	(1.6	)	(1.1	)	(3.4	)	(2.5	)
Comprehensive income attributable to Ensco	$124.5		$219.6		$311.6		$434.9

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Note 9 - Fair Value Measurements

 The following fair value hierarchy table categorizes information regarding our financial assets and liabilities measured at fair value on a recurring basis as of June 30, 2010 and December 31, 2009 (in millions):

	Quoted Prices in Active Markets for Identical Assets     (Level 1)			Significant Other Observable Inputs     (Level 2)		Significant Unobservable Inputs     (Level 3)		Total
As of June 30, 2010
Auction rate securities			$    --		$    --		$45.2		$45.2
Supplemental executive retirement    plan assets			19.3		--		--		19.3
Derivatives, net		--			3.0		--		3.0
Total financial assets		$19.3			$  3.0		$45.2		$67.5
As of December 31, 2009
Auction rate securities		$    --			$    --		$60.5		$60.5
Supplemental executive retirement    plan assets		18.7			--		--		18.7
Derivatives, net		--			13.2		--		13.2
Total financial assets		$18.7			$13.2		$60.5		$92.4

    Auction Rate Securities

 As of June 30, 2010 and December 31, 2009, we held long-term debt instruments with variable interest rates that periodically reset through an auction process ("auction rate securities") totaling $50.9 million and $66.8 million (par value), respectively.  These auction rate securities were classified as long-term investments on our condensed consolidated balance sheets. Our auction rate securities were originally acquired in January 2008 and have maturity dates ranging from 2025 to 2047. Our auction rate securities were measured at fair value on a recurring basis using significant Level 3 inputs as of June 30, 2010 and December 31, 2009.  The following table summarizes  the fair value measurements of our auction rate securities using significant Level 3 inputs, and changes therein, for the three-month and six-month periods ended June 30, 2010 and 2009 (in millions):

	Three Months Ended                June 30,			Six Months Ended           June 30,
	2010		2009	2010		2009
Beginning Balance	$55.4		$61.9	$60.5		$64.2
Sales	(10.5	)	(.3)	(15.9	)	(2.6)
Unrealized gains*	.3		--	.6		--
Transfers in and/or out of Level 3	--		--	--		--
Ending balance	$45.2		$61.6	$45.2		$61.6

*Unrealized gains were included in other income, net, in our condensed consolidated statements of income.

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 Before utilizing Level 3 inputs in our fair value measurement, we considered whether observable inputs were available. As a result of continued auction failures, quoted prices for our auction rate securities did not exist as of June 30, 2010. Accordingly, we concluded that Level 1 inputs were not available. Brokerage statements received from the three broker/dealers that held our auction rate securities included their estimated market value as of June 30, 2010.  All three broker/dealers valued our auction rate securities at par. Due to the lack of transparency into the methodologies used to determine the estimated marke t values, we have concluded that estimated market values provided on our brokerage statements do not constitute valid inputs, and we do not utilize them in measuring the fair value of our auction rate securities.

 We used an income approach valuation model to estimate the price that would be received in exchange for our auction rate securities in an orderly transaction between market participants ("exit price") as of June 30, 2010. The exit price was derived as the weighted-average present value of expected cash flows over various periods of illiquidity, using a risk-adjusted discount rate based on the credit risk and liquidity risk of our auction rate securities.  While our valuation model was based on both Level 2 (credit quality and interest rates) and Level 3 inputs, we determined that Level 3 inp uts were significant to the overall fair value measurement of our auction rate securities, particularly the estimates of risk-adjusted discount rates and ranges of expected periods of illiquidity. We have the ability to maintain our investment in these securities until they are redeemed, repurchased or sold in a market that facilitates orderly transactions.

    Supplemental Executive Retirement Plan Assets

 Our Ensco supplemental executive retirement plans (the "SERP") are non-qualified plans that provide for eligible employees to defer a portion of their compensation for use after retirement. Assets held in the SERP were marketable securities measured at fair value on a recurring basis using Level 1 inputs and were included in other assets, net, on our condensed consolidated balance sheets as of June 30, 2010 and December 31, 2009. The fair value measurement of assets held in the SERP was based on quoted market prices.

    Derivatives

 Our derivatives were measured at fair value on a recurring basis using Level 2 inputs as of June 30, 2010 and December 31, 2009. See "Note 4 - Derivative Instruments" for additional information on our derivatives, including a description of our foreign currency hedging activities and related methodologies used to manage foreign currency exchange rate risk. The fair value measurement of our derivatives was based on market prices that are generally observable for similar assets or liabilities at commonly-quoted intervals.

    Other Financial Instruments

 The carrying values and estimated fair values of our debt instruments as of June 30, 2010 and December 31, 2009 were as follows (in millions):

	June 30,                   2010		December 31,                    2009
	Carrying   Value	Estimated   Fair    Value	Carrying   Value	Estimated   Fair    Value
7.20% Debentures	$148.9	$157.8	$148.9	$155.9
6.36% Bonds, including current maturities	69.7	79.4	76.0	85.8
4.65% Bonds, including current maturities	47.2	53.2	49.5	53.8

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 The estimated fair value of our 7.20% Debentures was determined using quoted market prices. The estimated fair values of our 6. 36% Bonds and 4.65% Bonds were determined using an income approach valuation model. The estimated fair value of our cash and cash equivalents, receivables, trade payables and other liabilities approximated their carrying values as of June 30, 2010 and December 31, 2009.

    ENSCO I Impairment

 During the quarter ended June 30, 2010, we recorded a $12.2 million loss from the impairment of ENSCO I, the only barge rig in our fleet, which is currently cold-stacked in Singapore and is included in our Asia Pacific operating segment. The loss on impairment was included in contract drilling expe nse in our condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2010. The impairment resulted from the adjustment of the rig’s carrying value to its estimated fair value based on a change in our expectation that it is more-likely-than-not that the rig will be disposed of significantly before the end of its estimated useful life. ENSCO I was not classified as held-for-sale as of June 30, 2010, as a sale was not deemed probable of occurring within the next twelve months.

 We utilized an income approach valuation model to estimate the price that would be received in exchange for the rig in an orderly transaction between market participants as of June 30, 2010. The resulting exit price was derived as the present value of expected cash flows from the use and eventual d isposition of the rig, using a risk-adjusted discount rate.  Level 3 inputs were significant to the overall fair value measurement of ENSCO I, due to the limited availability of observable market data for similar assets.

Note 10 – Income Taxes

 Subsequent to our redomestication to the U.K. in December 2009, we reorganized our worldwide operations, which included, among other things, the transfer of ownership of several of our drilling rigs among our subsidiaries during the second quarter of 2010.  A $22.5 million income tax liability associated with the gain on the intercompany transfer was deferred and is being amortized on a straight-line basis over the remaining useful lives of the associated assets that were transferred, which range from five to thirty years. The pre-tax profit of the selling subsidiary resulting from the intercompany transfer was eliminated from our consolidated financial statements. Similarly, the carrying value of the assets in our consolidated financial statement s remained at the historical net depreciated cost prior to the intercompany transfer and did not reflect the asset disposal transaction of the selling subsidiary or the asset acquisition transaction of the acquiring subsidiary.

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Note 11 - Discontinued Operations

    Rig Sales

 In April 2010, we sold jackup rig ENSCO 57 for $47.1 million, of which $4.7 million was received in December 2009. We recognized a pre-tax gain of $17.9 million in connection with the disposal of ENSCO 57, which was included in gain on disposal of discontinued operations, net, in our condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2010. The rig’s net book value and inventory and other assets on the date of sale totaled $29.2 million. ENSCO 57 operating results were reclassified as discontinued operations in our condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2010 and 2009 and previously were included within our Asia Pacific operating segment.

 In March 2010, we sold jackup rigs ENSCO 50 and ENSCO 51 for an aggregate $94.7 million, of which $4.7 million was received in December 2009. We recognized an aggregate pre-tax gain of $33.9 million in connection with the disposals of ENSCO 50 and ENSCO 51, which was included in gain on disposal of discontinued operations, net, in our condensed consolidated statement of income for the six-month period ended June 30, 2010.  The two rigs' aggregate ne t book value and inventory and other assets on the date of sale totaled $60.8 million. ENSCO 50 and ENSCO 51 operating results were reclassified as discontinued operations in our condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2010 and 2009 and previously were included within our Asia Pacific operating segment.

    ENSCO 69

 From May 2007 to June 2009, ENSCO 69 was contracted to Petrosucre, a subsidiary of Petróleos de Venezuela S.A., the national oil company of Venezuela ("PDVSA"). In January 2009, we suspended drilling operations on ENSCO 69 after Petrosucre failed to satisfy its contractual obligations and meet commitments relative to the payment of past due invoices. Petrosucre then took over complete control of ENSCO 69 drilling operations utilizing Petrosucre employees and a portion of the Venezuelan rig crews we had utilized.

 On June 4, 2009, after Petrosucre's failure to satisfy its contractual payment obligations, failure to reach a mutually acceptable agreement with us and denial of our request to demobilize ENSCO 69 from Venezuela, Petrosucre advised that it would not return the rig and would continue to operate it without our consent. Petrosucre further advised that it would release ENSCO 69 after a six-month period, subject to a mutually agreed accord addressing the resolution of all remaining obligations under the ENSCO 69 drilling contract. On June 6, 2009, we terminated our contract with Petrosucre and removed all remaining Ensco employees from the rig.

17

 Due to Petrosucre's failure to satisfy its contractual obligations and meet payment commitments, and in consideration of the Venezuelan government's nationalization of assets owned by international oil and gas companies and oilfield service companies, we concluded it was remote that ENSCO 69 would be returned to us by Petrosucre and operated again by Ensco. Therefore, we recorded the disposal of ENSCO 69 during the second quarter of 2009. ENSCO 69 operating results were reclassified as discontinued operations in our condensed consolidated statements of income for the three-month and six-month periods end ed June 30, 2010 and 2009.

 In November 2009, we executed an agreement with Petrosucre to mitigate our losses and resolve issues relative to outstanding amounts owed by Petrosucre for drilling operations performed by Ensco through the date of termination of the drilling contract in June 2009 (the "agreement"). Although ENSCO 69 will continue to be fully controlled and operated by Petrosucre, the agreement requires Petrosucre to compensate us for its ongoing use of the rig. We recognized $5.5 million and $12.4 million of pre-tax income from discontinued operati ons for the three-month and six-month periods ended June 30, 2010 associated with collections under the agreement.

 Although the agreement obligates Petrosucre to make additional payments for its use of the rig through June 30, 2010, the associated income was not recognized in our condensed consolidated statements of income, as collectability was not reasonably assured.  There can be no assurances relative to the recovery of outstanding contract entitlements, insurance recovery and related pending litigation, the possible return of ENSCO 69 to us by Petrosucre or the imposition of cus toms duties in relation to the rig's ongoing presence in Venezuela.  See "Note 12 - Contingencies" for additional information on insurance and legal remedies related to ENSCO 69.

 The following table summarizes our income (loss) from discontinued operations for the three-month and six-month periods ended June 30, 2010 and 2009 (in millions):

	Three Months Ended             June 30,				Six Months Ended              June 30,
	2010		2009		2010	2009
Revenues	$ 5.0		$ 14.3		$24.7	$ 44.2
Operating expenses	1.3		19.4		10.7	42.2
Operating income (loss) before income taxes	3.7		(5.1	)	14.0	2.0
Income tax (benefit) expense	(.8	)	3.4		3.8	3.7
Gain (loss) on disposal of discontinued operations, net	5.7		(11.8	)	34.9	(11.8	)
Income (loss) from discontinued operations	$10.2		$(20.3	)	$45.1	$(13.5	)

 Debt and interest expense are not allocated to our discontinued operations.

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Note 12 - Contingencies

    FCPA Internal Investigation

 Following disclosures by other offshore service companies announcing internal investigations involving the legality of amounts paid to and by customs brokers in connection with temporary importation of rigs and vessels into Nigeria, the Audit Committee of our Board of Directors and management commenced an internal investigation in July 2007. The investigation initially focused on our payments to customs brokers relating to the temporary importation of ENSCO 100, our only rig that operated offshore Nigeria during the pertinent period.

 As is customary for companies operating offshore Nigeria, we had engaged independent customs brokers to process customs clearance of routine shipments of equipment, materials and supplies and to process the ENSCO 100 temporary importation permits, extensions and renewals. One or more of the customs brokers that our subsidiary in Nigeria used to obtain the ENSCO 100 temporary import permits, extensions and renewals also provided this service to other offshore service companies that have undertaken Foreign Corrupt Practices Act ("FCPA") compliance internal investiga tions.

 The principal purpose of our investigation was to determine whether any of the payments made to or by our customs brokers were inappropriate under the anti-bribery provisions of the FCPA or whether any violations of the recordkeeping or internal accounting control provisions of the FCPA occurred. Our Audit Committee engaged a Washington, D.C. law firm with significant experience in investigating and advising upon FCPA matters to assist in the internal investigation.

 Following notification to the Audit Committee and to KPMG LLP, our independent registered public accounting firm, in consultation with the Audit Committee's external legal counsel, we voluntarily notified the United States Department of Justice and SEC that we had commenced an internal investigation. We expressed our intention to cooperate with both agencies, comply with their directives and fully disclose the results of the investigation. The internal investigation process has involved extensive reviews of documents and records, as well as production to the authorities, and interviews of relevant personnel. In addition to the te mporary importation of ENSCO 100, the investigation has examined our customs clearance of routine shipments and immigration activities in Nigeria.

Our internal investigation has essentially been concluded. Discussions were held with the authorities to review the results of the investigation and discuss associated matters during 2009 and the first half of 2010.  On May 24, 2010, we received notification from the SEC Division of Enforcement advising that it does not intend to recommend any enforcement action.  We expect to receive a determination by the United States Department of Justice in the near-term. 

 Although we believe the United States Department of Justice will take into account our voluntary disclosure, our cooperation with the agency and the remediation and compliance enhancement activities that are underway, we are unable to predict the ultimate disposition of this matter, whether we will be charged with violation of the anti-bribery, recordkeeping or internal accounting control provisions of the FCPA or whether the scope of the investigation will be extended to other issues in Nigeria or to other countries. We also are unable to predict what potential corrective measures, fines, sanctions or other remedies, if any , the United States Department of Justice may seek against us or any of our employees.

 In November 2008, our Board of Directors approved enhanced FCPA compliance recommendations issued by the Audit Committee's external legal counsel, and the Company embarked upon an enhanced compliance initiative that included appointment of a Chief Compliance Officer and a Director - Corporate Compliance. We engaged consultants to assist us in implementing the compliance recommendations approved by our Board of Directors, which include an enhanced compliance policy, increased training and testing, prescribed contractual provisions for our service providers that interface with foreign government officials, due diligence f or the selection of such service providers and an increased Company-wide awareness initiative that includes periodic issuance of FCPA Alerts.

 Since ENSCO 100 completed its contract commitment and departed Nigeria in August 2007, this matter is not expected to have a material effect on or disrupt our current operations. As noted above, we are unable to predict the outcome of this matter or estimate the extent to which we may be exposed to any resulting potential liability, sanctions or significant additional expense.

19

    ENSCO 74 Loss

 In September 2008, ENSCO 74 was lost as a result of Hurricane Ike in the Gulf of Mexico.  Portions of its legs remained underwater adjacent to the customer's platform, and we conducted extensive aerial and sonar reconnaissance but did not locate the rig hull. The rig was a total loss, as defined under the terms of our insurance policies.

 In March 2009, the sunken rig hull of ENSCO 74 was located approximately 95 miles from the original drilling location when it was struck by an oil tanker. Following discovery of the sunken rig hull, we removed the accessible hydrocarbons onboard and began planning for removal of the wreckage. As an interim measure, the wreckage was appropriately marked, and the U.S. Coast Guard issued a Notice to Mariners.

 Physical damage to our rigs caused by a hurricane, the associated "sue and labor" costs to mitigate the insured loss and removal, salvage and recovery costs are all covered by our property insurance policies subject to a $50.0 million per occurrence self-insured retention.  The insured value of ENSCO 74 was $100.0 million, and we have received the net $50.0 million due under our policy for loss of the rig.

 Coverage for ENSCO 74 sue and labor costs and wreckage and debris removal costs under our property insurance policies is limited to $25.0 million and $50.0 million, respectively. Supplemental wreckage and debris removal coverage is provided under our liability insurance policies, subject to an annual aggregate limit of $500.0 million. We also have a customer contractual indemnification that provides for reimbursement of any ENSCO 74 wreckage and debris removal costs that are not recovered under our insurance policies.

 We believe it is probable that we are required to remove the leg sections of ENSCO 74 remaining adjacent to the customer's platform because they may interfere with the customer's future operations, and we recently commenced removal of the hull wreckage and related debris.  We estimate the leg removal costs to range from $16.0 million to $30.0 million and the costs of the hull and related debris removal to range from $36.0 million to $55.0 million. We expect the cost of removal of the legs and the hull and related debris to be fully covered by our insurance without any additional retention.

 A $16.0 million liability, representing the low end of the range of estimated leg removal costs, and a corresponding receivable for recovery of those costs was recorded as of June 30, 2010. A $34.3 million liability, representing the low end of the range of estimated remaining hull and related debris removal costs, and a corresponding receivable for recovery of those costs was recorded as of June 30, 2010. As of June 30, 2010, $1.7 million of wreckage and debris removal costs had been incurred and paid, primarily related to removal of hydrocarbons from the rig. The remaining estimated aggregate $50.3 million liability for leg and hull and related debris removal costs was included in accru ed liabilities and other in our June 30, 2010 condensed consolidated balance sheet.  The aggregate $50.8 million receivable for recovery of those costs was included in other assets, net, on our June 30, 2010 condensed consolidated balance sheet.

 In March 2009, we received notice from legal counsel representing certain underwriters in a subrogation claim alleging that ENSCO 74 caused a pipeline to rupture during Hurricane Ike. On September 4, 2009, civil litigation was filed seeking damages for the cost of repairs and business interruption in an amount in excess of $26.0 million. Based on information currently available, primarily the adequacy of available defenses, we have not concluded that it is probable a liability exists with respect to this matter.

 In March 2009, the owner of the oil tanker that struck the hull of ENSCO 74 commenced civil litigation against us seeking monetary damages of $10.0 million for losses incurred when the tanker struck the sunken hull of ENSCO 74. Based on information currently available, primarily the adequacy of available defenses, we have not concluded that it is probable a liability exists with respect to this matter.

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 We filed a petition for exoneration or limitation of liability under U.S. admiralty and maritime law in September 2009. The petition seeks exoneration from or limitation of liability for any and all injury, loss or damage caused, occasioned or occurred in relation to the ENSCO 74 loss in September 2008. The owner of the tanker that struck the hull of ENSCO 74 and the owners of four subsea pipelines have presented claims in the exoneration/limitation proceedings.  The matter is scheduled for trial in September 2011.

 We have liability insurance policies that provide coverage for claims such as the tanker and pipeline claims as well as removal of wreckage and debris in excess of the property insurance policy sublimit, subject to a $10.0 million per occurrence self-insured retention for third-party claims and an annual aggregate limit of $500.0 million. We believe all liabilities associated with the ENSCO 74 loss during Hurricane Ike resulted from a single occurrence under the terms of the applicable insurance policies. However, legal counsel for certain liability underwriters have ass erted that the liability claims arise from separate occurrences. In the event of multiple occurrences, the self-insured retention is $15.0 million for two occurrences and $1.0 million for each occurrence thereafter.

 Although we do not expect final disposition of the claims associated with the ENSCO 74 loss to have a material adverse effect upon our financial position, operating results or cash flows, there can be no assurances as to the ultimate outcome.

    ENSCO 69

We have filed an insurance claim under our package policy, which includes coverage for certain political risks, and are evaluating legal remedies against Petrosucre for contractual and other ENSCO 69 related damages. ENSCO 69 has an insured value of $65.0 million under our package policy, subject to a $10.0 million deductible.

 In September 2009, legal counsel acting for the package policy underwriters denied coverage under the package policy and reserved rights. In March 2010, underwriters commenced litigation in the U.K. for purposes of enforcing mediation under the disputes clause of our package policy and precluding us from pursuing litigation in the United States. On that date, we commenced litigation to recover on our political risk package policy claim. Our lawsuit seeks recovery under the policy for the loss of E NSCO 69 and includes claims for wrongful denial of coverage, breach of contract, breach of the Texas insurance code, failure to timely respond to the claim and bad faith. Our lawsuit seeks actual damages in the amount of $55.0 million (insured value of $65.0 million less a $10.0 million deductible), punitive damages and attorneys' fees. On April 26, 2010, we obtained a temporary injunction that effectively prohibits the insurance underwriters from pursuing litigation they filed in the U.K.

 We were unable to conclude that collection of insurance proceeds associated with the loss of ENSCO 69 was probable as of June 30, 2010. Accordingly, no ENSCO 69 related insurance receivables were recorded on our condensed consolidated balance sheet as of June 30, 2010. See "Note 11 - Discontinued Operations" for additional information on ENSCO 69.

    ENSCO 29 Wreck Removal

 A portion of the ENSCO 29 platform drilling rig was lost over the side of a customer's platform as a result of Hurricane Katrina during 2005. Although beneficial ownership of ENSCO 29 was transferred to our insurance underwriters when the rig was determined to be a total loss, management believes we may be legally required to remove ENSCO 29 wreckage and debris from the seabed and currently estimates the removal cost could range from $5.0 million to $15.0 million. Our property insurance policies include coverage for ENSCO 29 wreckage and debris removal costs up to $ 3.8 million. We also have liability insurance policies that provide specified coverage for wreckage and debris removal costs in excess of the $3.8 million coverage provided under our property insurance policies.

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 Our liability insurance underwriters have issued letters reserving rights and effectively denying coverage by questioning the applicability of coverage for the potential ENSCO 29 wreckage and debris removal costs.  During 2007, we commenced litigation against certain underwriters alleging breach of contract, wrongful denial, bad faith and other claims which seek a declaration that removal of wreckage and debris is covered under our liability insurance, monetary damages, attorneys' fees and other remedies. The matter is scheduled for trial in August 2010.

 While we anticipate that any ENSCO 29 wreckage and debris removal costs incurred will be largely or fully covered by insurance, a $1.2 million provision, representing the portion of the $5.0 million low end of the range of estimated removal cost we believe is subject to liability insurance coverage, was recognized during 2006.

    Asbestos Litigation

 During 2004, we and certain current and former subsidiaries were named as defendants, along with numerous other third-party companies as co-defendants, in three multi-party lawsuits filed in Mississippi. The lawsuits sought an unspecified amount of monetary damages on behalf of individuals alleging personal injury or death, primarily under the Jones Act, purportedly resulting from exposure to asbestos on drilling rigs and associated facilities during the period 1965 through 1986.

 In compliance with the Mississippi Rules of Civil Procedure, the individual claimants in the original multi-party lawsuits whose claims were not dismissed were ordered to file either new or amended single plaintiff complaints naming the specific defendant(s)  against whom they intended to pursue claims. As a result, out of more than 600 initial multi-party claims, we have been named as a defendant by 65 individual plaintiffs. Of these claims, 62 claims or lawsuits are pending in Mississippi state courts and three are pending in the U.S. District Court as a result of their removal from state court.

 To date, written discovery and plaintiff depositions have taken place in eight cases involving us.  While several cases have been selected for trial during 2010 and 2011, none of the cases pending against us in Mississippi state court are included within those selected cases.

We intend to vigorously defend against these claims and have filed responsive pleadings preserving all defenses and challenges to jurisdiction and venue. However, discovery is still ongoing and, therefore, available information regarding the nature of all pending claims is limited. At present, we cannot reasonably determine how many of the claimants may have valid claims under the Jones Act or estimate a range of potential liability exposure, if any.

 In addition to the pending cases in Mississippi, we have two other asbestos or lung injury claims pending against us in litigation in other jurisdictions. Although we do not expect the final disposition of the Mississippi and other asbestos or lung injury lawsuits to have a material adverse effect upon our financial position, operating results or cash flows, there can be no assurances as to the ultimate outcome of the lawsuits.

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    Working Time Directive

 Legislation known as the U.K. Working Time Directive ("WTD") was introduced during 2003 and may be applicable to our employees and employees of other drilling contractors that work offshore in U.K. territorial waters or in the U.K. sector of the North Sea. Certain trade unions representing offshore employees have claimed that drilling contractors are not in compliance with the WTD in respect of paid time off (vacation time) for employees working offshore on a rotational basis (generally equal time working and off).

 A Labor Tribunal in Aberdeen, Scotland, rendered decisions in claims involving other offshore drilling contractors and offshore service companies in February 2008. The Tribunal decisions effectively held that employers of offshore workers in the U.K. sector employed on an equal time on/time off rotation are obligated to accord such rotating personnel two-weeks annual paid time off from their scheduled offshore work assignment period. Both sides of the matter, employee and employer groups, appealed the Tribunal decision. The appeals were heard by the Employment Appeal Tribunal ("EAT") in December 2008.

 In an opinion rendered in March 2009, the EAT determined that the time off work enjoyed by U.K. offshore oil and gas workers, typically 26 weeks per year, meets the amount of annual leave employers must provide to employees under the WTD. The employer group was successful in all arguments on appeal, as the EAT determined that the statutory entitlement to annual leave under the WTD can be discharged through normal field break arrangements for offshore workers. As a consequence of the EAT decision, an equal on/off time offshore rotation has been deemed to be fully compliant with the WTD.  The employee group (led by a trade union) was granted leave to appeal to the highest civil court in Scotland (the Court of Session).  A hearing on the appeal occurred in June 2010 and a decision is expected in the near-term.

 Based on information currently available, we do not expect the ultimate resolution of these matters to have a material adverse effect on our financial position, operating results or cash flows.

    Other Matters

 In addition to the foregoing, we are named defendants in certain other lawsuits, claims or proceedings incidental to our business and are involved from time to time as parties to governmental investigations or proceedings, including matters related to taxation, arising in the ordinary course of business. Although the outcome of such lawsuits or other proceedings cannot be predicted with certainty and the amount of any liability that could arise with respect to such lawsuits or other proceedings cannot be predicted accurately, we do not expect these matters to have a material adverse effect on our financial position, operating res ults or cash flows.

Note 13 - Segment Information

 Our business consists of four operating segments: (1) Deepwater, (2) Asia Pacific, (3) Europe and Africa (4) North and South America. Each of our four operating segments provides one service, contract drilling. Segment information for the three-month and six-month periods ended June 30, 2010 and 2009 is presented below (in millions). General and administrative expense is not allocated to our operating segments for purposes of measuring segment operating income and is included in "Reconciling Items." Assets not allocated to our operating segments consisted primarily of cash and cash equivalents and goodwill and also are inclu ded in "Reconciling Items."

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Three Months Ended June 30, 2010	Deepwater	Asia Pacific	Europe and Africa	North  and  South  America	Operating   Segments      Total	Reconciling     Items		Consolidated     Total
Revenues	$   120.9	$    121.3	$  73.5	$  90.6	$   406.3	$         --		$   406.3
Operating expenses Contract drilling (exclusive of depreciation)	46.5	65.8	51.0	43.7	207.0	--		207.0
Depreciation	9.7	18.2	11.9	12.7	52.5	.3		52.8
General and administrative	--	--	--	--	--	22.0		22.0
Operating income (loss)	$     64.7	$     37.3	$  10.6	$  34.2	$   146.8	$    (22.3	)	$   124.5
Total assets	$2,774.8	$1,153.2	$822.9	$794.5	$5,545.4	$1,375.6		$6,921.0

Three Months Ended June 30, 2009	Deepwater	Asia  Pacific	Europe and Africa	North  and  South  America	Operating   Segments      Total	Reconciling     Items		Consolidated     Total
Revenues	$     67.7	$   147.2	$176.0	$106.4	$   497.3	$         --		$   497.3
Operating expenses Contract drilling (exclusive of depreciation)	23.7	54.4	52.6	40.5	171.2	--		171.2
Depreciation	3.7	18.7	11.0	12.1	45.5	.3		45.8
General and administrative	--	--	--	--	--	16.0		16.0
Operating income (loss)	$     40.3	$     74.1	$112.4	$  53.8	$   280.6	$    (16.3	)	$   264.3
Total assets	$2,172.4	$1,300.7	$813.2	$823.4	$5,109.7	$1,239.3		$6,349.0

Six Months Ended June 30, 2010	Deepwater	Asia  Pacific	Europe and Africa	North  and  South  America	Operating   Segments     Total	Reconciling     Items		Consolidated     Total
Revenues	$   251.3	$    253.3	$161.1	$182.1	$   847.8	$         --		$   847.8
Operating expenses Contract drilling (exclusive of depreciation)	91.5	117.6	98.1	82.6	389.8	--		389.8
Depreciation	19.5	36.5	23.7	25.2	104.9	.6		105.5
General and administrative	--	--	--	--	--	42.6		42.6
Operating income (loss)	$   140.3	$     99.2	$  39.3	$  74.3	$   353.1	$    (43.2	)	$   309.9
Total assets	$2,774.8	$1,153.2	$822.9	$794.5	$5,545.4	$1,375.6		$6,921.0

Six Months Ended June 30, 2009	Deepwater	Asia  Pacific	Europe and Africa	North  and  South  America	Operating     Segments       Total	Reconciling     Items		Consolidated     Total
Revenues	$   67.7	$  343.0	$372.4	$198.4	$   981.5	$         --		$    981.5
Operating expenses Contract drilling (exclusive of depreciation)	28.5	111.6	106.1	79.6	325.8	--		325.8
Depreciation	6.0	37.0	21.9	24.1	89.0	.6		89.6
General and administrative	--	--	--	--	--	28.0		28.0
Operating income (loss)	$     33.2	$   194.4	$244.4	$  94.7	$   566.7	$    (28.6	)	$   538.1
Total assets	$2,172.4	$1,300.7	$813.2	$823.4	$5,109.7	$1,239.3		$6,349.0

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    Information about Geographic Areas

 As of June 30, 2010, our Deepwater operating segment consisted of three ultra-deepwater semisubmersible rigs located in the Gulf of Mexico, one ultra-deepwater semisubmersible rig located in Australia and four ultra-deepwater semisubmersible rigs under construction in Singapore. Our Asia Pacific operating segment consisted of 16 jackup rigs and one barge rig deployed in various locations throughout Asia, the Middle East and Australia. Our Europe and Africa operating segment consisted of eight jackup rigs deployed in various territorial waters of the North Sea and two jackup rigs located offshore Tunisia. Our North and South America operating segment co nsisted of eight jackup rigs located in the Gulf of Mexico and five jackup rigs located offshore Mexico.

 Certain of our ultra-deepwater semisubmersible rigs currently contracted in the U.S. Gulf of Mexico are affected by a drilling moratorium/suspension imposed by the U.S. Department of Interior in response to the BP Macondo well incident. This moratorium/suspension and related Notices to Lessees (“NTLs”) are being challenged in litigation by Ensco and others.  The operations of certain of our jackup rigs not expressly covered by the moratorium/suspension are being delayed due to the requirements of the NTLs and the permit approval process.   Current or future NTLs or other directives may impact our customers' abi lity to obtain permits and commence or continue deepwater or shallow-water operations in the U.S. Gulf of Mexico. During the three-month and six-month periods ended June 30, 2010, revenues provided by our drilling operations in the U.S. Gulf of Mexico totaled $93.8 million and $188.4 million, or 23% and 22%, of our consolidated revenues, respectively. Of these amounts, 62% and 65% were provided by our deepwater drilling operations in the U.S. Gulf of Mexico for the three-month and six-month periods ended June 30, 2010, respectively. A prolonged suspension of drilling activity in the U.S. Gulf of Mexico and associated new legislation or regulations in the U.S. or elsewhere could materially adversely affect our financial condition, operating results or cash flows.

Note 14 - Subsequent Events

 On July 7, 2010, we acquired a KFELS Super B Class design jackup rig for $186.0 million, of which $18.6 million was paid as a deposit in June 2010.  The rig was constructed in 2008 and has been renamed ENSCO 109.  ENSCO 109 is currently operating offshore Australia and will be reported within our Asia Pacific operating segment in future periods.

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Item 2.  Management's Discussion and Analysis of Financial Condition and Results of Operations

BUSINESS ENVIRONMENT

 In May 2010, the U.S. Department of Interior implemented a six-month moratorium/suspension on certain drilling activities in water depths greater than 500 feet in the U.S. Gulf of Mexico in response to the BP Macondo well incident. The U.S. Department of Interior subsequently issued Notices to Lessees ("NTLs") implementing additional saf ety and certification requirements applicable to drilling activities in the U.S. Gulf of Mexico, imposed additional requirements for approval of development and production activities in the U.S. Gulf of Mexico and has delayed the approval of applications to drill in both deepwater and shallow-water areas. On June 22, 2010, the U.S. District Court for the Eastern District of Louisiana granted a temporary injunction which immediately prohibited enforcement of the moratorium/suspension and an appeal to the Fifth Circuit Court of Appeals declined the government's petition to stay enforcement of the injunction.  On July 12, 2010, the U.S. Department of Interior issued a revised moratorium/suspension on drilling in the U.S. Gulf of Mexico that generally applies to mobile offshore drilling units that utilize subsea blowout prevention equipment required for deepwater drilling operations.

 Some U.S. Gulf of Mexico deepwater projects have been delayed as a result of the moratorium/suspension, which does not prohibit certain well operations.  Although global deepwater drilling activity has remained stable during 2010, there is significant uncertainty as to the near-term and long-term impact the BP Macondo well incident may have on deepwate r drilling in the U.S. Gulf of Mexico, in addition to its potential impact on the global deepwater market.

 Semisubmersible rig supply also continues to increase as a result of newbuild construction programs. It has been reported that 29 newbuild semisubmersible rigs are currently under construction, approximately half of which are scheduled for delivery during the remainder of 2010. The majority of semisubmersible rigs scheduled for delivery during 2010 are contracte d. Based on the current level of uncertainty regarding deepwater drilling in the U.S. Gulf of Mexico, we are unable to predict whether newbuild semisubmersible rigs will be absorbed into the global market without a significant effect on utilization and day rates.

 The significant decline in oil and natural gas prices during the latter half of 2008 and the deterioration of the global economy led to an abrupt reduction in demand for jackup rigs during 2009. Although oil prices have stabilized, incremental drilling activity during 2010 has remained limited resulting in continued softness in jackup rig day rates. While we are encouraged by continued rig inquiries, it remains uncertain whether they will ultimately result in a measurable increase in jackup rig demand in the near - -term. Furthermore, it is uncertain as to the impact the BP Macondo well incident may have on jackup rig demand in general, and in the U.S. Gulf of Mexico in particular.

 Jackup rig supply continues to increase as a result of newbuild construction programs which were initiated prior to the 2008 decline in oil and natural gas prices. It has been reported that 41 newbuild jackup rigs are currently under construction, over half of which are scheduled for delivery during the remainder of 2010. The majority of jackup rigs scheduled for delivery during 2010 are not contracted. It is unlikely that the market in general or any geographic region in particular will be able to fully absorb newbui ld jackup rig deliveries in the near-term, especially in consideration of the existing oversupply of jackup rigs.

 For additional information concerning the potential impact the aforementioned events and circumstances may have on our business, our industry and global supply, see "Item 1A. Risk Factors" in Part I and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II of our Annual Report on Form 10-K for the year ended December 31, 2009, as updated in the Current Report on Form 8-K dated June 8, 2010 and in this report. 

    Deepwater

 During 2009, depressed oil and natural gas prices resulted in a modest decline in demand for ultra-deepwater semisubmersible rigs, however, global utilization and day rates generally were stable. Although utilization and day rates remained stable during the first six months of 2010, utilization and day rates may come under pressure if deepwater contracts in the U.S. Gulf of Mexico are terminated and/or those rigs are marketed in other regions.  Future ultra-deepwater semisubmersible rig utilization and day r ates will depend in large part on projected oil and natural gas prices, the global economy and the potential long-term impact the BP Macondo well incident may have on the global deepwater market.

 ENSCO 8502 was delivered in January 2010 and is scheduled to commence drilling operations under a two-year contract in August 2010.  Although our customer has questioned whether the new requirements of the moratorium/suspension and related NTLs will delay contract commencement, we believe ENSCO 8502 is in compliance with contractual requirements and current applicable regulations and that the drilling contract should commence in accordance with its terms.  We also have four ENSCO 8500 Series® rigs under construct ion with scheduled delivery dates during the fourth quarter of 2010, the second half of 2011 and the first and second half of 2012. ENSCO 8503 is committed under a long-term drilling contract in the Gulf of Mexico and is scheduled to commence drilling operations during the first quarter of 2011.  The remaining ENSCO 8500 Series® rigs under construction are without contracts. Our ENSCO 7500 ultra-deepwater semisubmersible rig currently is operating under contract in Australia.

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    Asia Pacific

 During 2009, Asia Pacific jackup rig utilization and day rates were significantly impacted by the 2008 decline in oil and natural gas prices. While the Asia Pacific jackup market began to show signs of stability during the first six months of 2010, competition for work remained intense due to the oversupply of jackup rigs and limited contract opportunities. With an expected increase in the supply of available jackup rigs from newbuild deliveries and expiring drilling contracts, we anticipate that Asia Pacific jackup r ig utilization and day rates will remain under pressure in the near-term.

 In conjunction with our long-established strategy of high-grading our jackup rig fleet by investing in newer equipment, we sold three jackup rigs located in the Asia Pacific region during the first six months of 2010.  In July 2010, we acquired a KFELS Super B Class design jackup rig constructed in 2008.  The rig was renamed ENSCO 109 and is currently operating in Australia.

    Europe and Africa

 Our Europe and Africa offshore drilling operations are mainly conducted in Northern Europe. The 2008 decline in oil and natural gas prices resulted in several cancelled tenders and unexercised contract extension options during the latter portion of 2009. Tender activity in the region during the first six months of 2010 was limited with some inquiries for work beginning in 2011, and we expect this trend to continue in the near-term. With limited tender activity and additional jackup rigs projected to complete their cur rent contracts later this year, we anticipate this market will experience excess rig availability, and utilization and day rates will remain under pressure in the near-term.

    North and South America

 A significant portion of our North and South America offshore drilling operations are conducted in Mexico, where demand for rigs increased in recent years as Petróleos Mexicanos ("PEMEX"), the national oil company of Mexico, accelerated drilling activities in an attempt to offset continued depletion of its major oil and natural gas fields. During 2009 and the first six months of 2010, demand for jackup rigs in Mexico remained high despite global economic conditions. PEMEX recently issued additional tenders for se veral jackup rigs to commence drilling operations in late 2010 in response to contracts expiring later this year. We expect future day rates in Mexico to face pressure as jackup rig contracts in the region expire and drilling contractors with idle rigs in the Gulf of Mexico and other geographic regions pursue the available contract opportunities.

 We also conduct a portion of our North and South America jackup rig operations in the U.S. Gulf of Mexico. The U.S. Gulf of Mexico jackup rig market remained extremely weak during 2009, with drilling activity reaching historic lows as a result of the deterioration in the global economy. During early 2010, tender activity in the U.S. Gulf of Mexico improved as operators capitalized on cost-effective terms offered by drilling contractors. Due to the potential for delays from hurricane season, certain operators ’ inability to timely obtain drilling permits and the uncertainty regarding the impact the BP Macondo well incident may have on jackup rig drilling operations in the region, we do not expect meaningful improvement in U.S. Gulf of Mexico jackup rig utilization and day rates in the near-term.

RESULTS OF OPERATIONS

 The following table summarizes our condensed consolidated results of operations for the three-month and six-month periods ended June 30, 2010 and 2009 (in millions):

	Three Months Ended          June 30,				Six Months Ended           June 30,
	2010		2009		2010		2009
Revenues	$406.3		$497.3		$847.8		$981.5
Operating expenses
Contract drilling (exclusive of depreciation)	207.0		171.2		389.8		325.8
Depreciation	52.8		45.8		105.5		89.6
General and administrative	22.0		16.0		42.6		28.0
Operating income	124.5		264.3		309.9		538.1
Other income, net	12.8		6.9		15.9		2.6
Provision for income taxes	19.6		49.5		51.4		103.7
Income from continuing operations	117.7		221.7		274.4		437.0
Income (loss) from discontinued operations, net	10.2		(20.3	)	45.1		(13.5	)
Net income	127.9		201.4		319.5		423.5
Net income attributable to noncontrolling interests	(1.6	)	(1.1	)	(3.4	)	(2.5	)
Net income attributable to Ensco	$126.3		$200.3		$316.1		$421.0

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 For the quarter ended June 30, 2010, revenues declined by $91.0 million, or 18%, and operating income declined by $139.8 million, or 53%, as compared to the prior year quarter. For the six-month period ended June 30, 2010, revenues declined by $133.7 million, or 14%, and operating income declined by $228.2 million, or 42%, as compared to the prior year period. These decl ines were primarily due to a decline in average day rates and utilization for our Europe and Africa and Asia Pacific jackup rig fleets, partially offset by significant increases in revenues and operating income generated by our ultra-deepwater semisubmersible rig fleet.

 A significant number of our drilling contracts are of a long-term nature. Accordingly, a decline in demand for contract drilling services typically affects our operating results and cash flows gradually over many quarters as long-term contracts expire. The significant decline in oil and natural gas prices during the latter half of 2008 and the deterioration of the global economy resulted in a dramati c decline in demand for contract drilling services during 2009, which will continue to negatively impact our operating results during 2010.  While we have substantial contract backlog for 2010, it is unlikely that revenue and operating income levels achieved during 2009 will be sustained during 2010.

 Certain of our ultra-deepwater semisubmersible rigs currently contracted in the U.S. Gulf of Mexico are affected by the drilling moratorium/suspension imposed by the U .S. Department of Interior in response to the BP Macondo well incident.  This moratorium/suspension and related NTLs are being challenged in litigation by Ensco and others.  The operations of certain of our jackup rigs not expressly covered by the moratorium/suspension are being delayed due to the requirements of the NTLs and the drilling permit approval process.   Current or future NTLs or other directives may impact our customers' ability to obtain drilling permits and commence or continue deepwater or shallow-water operations in the U.S. Gulf of Mexico.

 Customers recently have submitted force majeure notices involving our ultra-deepwater semisubmersible (ENSCO 8500) and four of our jackup rigs (ENSCO 68, ENSCO 82, ENSCO 86 and ENSCO 87) in the U.S. Gulf of Mexico.  We have rejected all of these force majeure notices as invalid under the applicable terms of the contract.  All four jackup rigs (ENSCO 68, ENSCO 82, ENSCO 86 and ENSCO 87) currently are operating and earning full day rate.  In the event of valid force majeure circu mstances, the contracts for our ultra-deepwater semisubmersible rigs currently in the U.S. Gulf of Mexico generally provide that a reduced rate applies for a specified number of days (approximately ten weeks) after which our customers have a right to terminate, subject to payment of a significant portion of the day rate for the remainder of the contract term (which, in some cases, is to be offset by other drilling work obtained during said period).  As respects our jackup rigs in the U.S. Gulf of Mexico, the contractual force majeure provisions generally provide for payment of full day rate for a specified number of days (approximately two weeks) after which our customers have a right to terminate without further payment.

 We are working with our customers on mutually agreeable contingency plans for our rigs in the U.S. Gulf of Mexico that may involve day rate adjustments or rig relocati ons. As respects ENSCO 8502, our customer has questioned whether the new requirements of the moratorium/suspension and related NTLs will delay contract commencement.  We believe ENSCO 8502 is in compliance with contractual requirements and current applicable regulations and that the drilling contract should commence in accordance with its terms.

 Significant uncertainty remains as to the near-term and long-term impact the BP Macondo well incident may have on our operating results in general, and in the U.S. Gulf of Mexico in particular.

Rig Locations, Utilization and Average Day Rates

 We manage our business through four operating segments. Our jackup rigs are mobile and occasionally move between operating segments in response to market conditions and contract opportunities. The following table summarizes our offshore drilling rigs by segment and rigs under construction as of June 30, 2010 and 2009:

	June 30,   2010	June 30,    2009
Deepwater(1)	4	3
Asia Pacific	17	17
Europe and Africa	10	10
North and South America	13	13
Under construction	4	5
Total(2)	48	48

(1)	In January 2010, we accepted delivery of ENSCO 8502, which is scheduled to commence drilling operations in the Gulf of Mexico under a two-year contract in August 2010.
(2)	The total number of rigs for each period excludes rigs reclassified as discontinued operations.

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The following table summarizes our rig utilization and average day rates from continuing operations by operating segment for the three-month and six-month periods ended June 30, 2010 and 2009:

	Three Months Ended           June 30,		Six Months Ended               June 30,
	2010	2009	2010	2009
Rig utilization(1)
Deepwater	91%	96%	95%	98%
Asia Pacific(3)	68%	69%	72%	75%
Europe and Africa	63%	87%	66%	93%
North and South America	87%	72%	86%	70%
Total	74%	75%	76%	79%
Average day rates(2)
Deepwater	$403,307	$490,865	$407,334	$490,865
Asia Pacific(3)	116,529	142,195	116,716	152,290
Europe and Africa	125,257	219,715	133,423	219,309
North and South America	82,939	119,190	85,482	119,127
Total	$131,231	$171,428	$135,033	$169,567

(1)	Rig utilization is derived by dividing the number of days under contract by the number of days in the period. Days under contract equals the total number of days that rigs have earned a day rate, including days associated with compensated downtime and mobilizations. For newly constructed or acquired rigs, the number of days in the period begins upon commencement of drilling operations for rigs with a contract or when the rig becomes available for drilling operations for rigs without a contract.
(2)	Average day rates are derived by dividing contract drilling revenues, adjusted to exclude certain types of non-recurring reimbursable revenues and lump sum revenues, by the aggregate number of contract days, adjusted to exclude contract days associated with certain mobilizations, demobilizations, shipyard contracts and standby contracts.
(3)	Rig utilization and average day rates for the Asia Pacific operating segment include our jackup rigs only. The ENSCO I barge rig has been excluded.

 Detailed explanations of our operating results, including discussions of revenues, contract drilling expense and depreciation expense by operating segment, are provided below.

Operating Income

 Our business consists of four operating segments: (1) Deepwater, (2) Asia Pacific, (3) Europe and Africa (4) North and South America. Each of our four operating segments provides one service, contract drilling. Segment information for the three-month and six-month periods ended June 30, 2010 and 2009 is presented below (in millions). General and administrative expense is not allocated to our operating segments for purposes of measuring segment operating income and is included in "Reconciling Items."

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Three Months Ended June 30, 2010

	Deepwater	Asia  Pacific	Europe and Africa	North   and   South  America	Operating   Segments      Total	Reconciling    Items	Consolidated     Total
Revenues	$120.9	$121.3	$73.5	$90.6	$406.3	$      --	$406.3
Operating expenses Contract drilling (exclusive of depreciation)	46.5	65.8	51.0	43.7	207.0	--	207.0
Depreciation	9.7	18.2	11.9	12.7	52.5	.3	52.8
General and administrative	--	--	--	--	--	22.0	22.0
Operating income (loss)	$ 64.7	$ 37.3	$10.6	$34.2	$146.8	$(22.3)	$124.5

Three Months Ended June 30, 2009

	Deepwater	Asia  Pacific	Europe and Africa	North   and   South  America	Operating   Segments      Total	Reconciling    Items	Consolidated     Total
Revenues	$ 67.7	$147.2	$176.0	$106.4	$497.3	$      --	$497.3
Operating expenses Contract drilling (exclusive of depreciation)	23.7	54.4	52.6	40.5	171.2	--	171.2
Depreciation	3.7	18.7	11.0	12.1	45.5	.3	45.8
General and administrative	--	--	--	--	--	16.0	16.0
Operating income (loss)	$ 40.3	$  74.1	$112.4	$  53.8	$280.6	$(16.3)	$264.3

Six Months Ended June 30, 2010

	Deepwater	Asia  Pacific	Europe and Africa	North   and   South   America	Operating   Segments      Total	Reconciling    Items	Consolidated     Total
Revenues	$251.3	$253.3	$161.1	$182.1	$847.8	$      --	$847.8
Operating expenses Contract drilling (exclusive of depreciation)	91.5	117.6	98.1	82.6	389.8	--	389.8
Depreciation	19.5	36.5	23.7	25.2	104.9	.6	105.5
General and administrative	--	--	--	--	--	42.6	42.6
Operating income (loss)	$140.3	$ 99.2	$ 39.3	$  74.3	$353.1	$(43.2)	$309.9

Six Months Ended June 30, 2009

	Deepwater	Asia  Pacific	Europe and Africa	North   and   South   America	Operating   Segments     Total	Reconciling    Items	Consolidated     Total
Revenues	$67.7	$343.0	$372.4	$198.4	$981.5	$      --	$981.5
Operating expenses Contract drilling (exclusive of depreciation)	28.5	111.6	106.1	79.6	325.8	--	325.8
Depreciation	6.0	37.0	21.9	24.1	89.0	.6	89.6
General and administrative	--	--	--	--	--	28.0	28.0
Operating income (loss)	$33.2	$194.4	$244.4	$  94.7	$566.7	$(28.6)	$538.1

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    Deepwater

 Deepwater revenues for the quarter ended June 30, 2010 increased by $53.2 million as compared to the prior year quarter. The increase in revenues was due to revenues earned by ENSCO 8500 and ENSCO 8501 which commenced drilling operations under long-term contracts during the second and fourth quarters of 2009, respectively.  Contract drilling expense increased by $22.8 million, due to the commencement of ENSCO 8500 and ENSCO 8501 drilling operations as pr eviously noted. Depreciation expense increased by $6.0 million, due to the addition of ENSCO 8500 and ENSCO 8501 to our deepwater fleet in the second and fourth quarters of 2009, respectively.

 Deepwater revenues for the six-month period ended June 30, 2010 increased by $183.6 million as compared to the prior year period. The increase in revenues was due to the deferral of ENSCO 7500 revenues during the first quarter of 2009 as the rig mobilized from the Gulf of Mexico to Australia and due to revenues earned by ENSCO 8500 and ENSCO 8501 which commenced drilling operations under long-term contracts during the second and fourth quarters of 2009, respectively. Contract drilling expense increased by $63.0 million, primarily due to the deferral of certain costs during the first quarter of 2009 associated with the ENSCO 7500 mobilization to Australia and the commencement of ENSCO 8500 and ENSCO 8501 drilling operations as previously noted. Depreciation expense increased by $13.5 million, due to the addition of ENSCO 8500 and ENSCO 8501 to our deepwater fleet in the second and fourth quarters of 2009, respectively.

    Asia Pacific

 Asia Pacific revenues for the quarter ended June 30, 2010 declined by $25.9 million, or 18%, as compared to the prior year quarter. The decline in revenues was primarily due to an 18% decline in average day rates as compared to the prior year quarter.  The decline in average day rates occurred due to lower levels of spending by oil and gas companies in response to the current economic environment, coupled with excess rig availability in the region.& #160; Contract drilling expense increased by $11.4 million, or 21%, as compared to the prior year quarter, primarily due to a $12.2 million loss on impairment of ENSCO I, our only barge rig, partially offset by a modest decline in payroll expense. Depreciation expense was comparable to the prior year quarter.

 Asia Pacific revenues for the six-month period ended June 30, 2010 declined by $89.7 million, or 26%, as compared to the prior year period. The decline in revenues was primarily due to a 23% decline in average day rates and, to a lesser extent, a decline in utilization to 72% from 75% in the comparable prior year period. The decline in average day rates and utilization occurred due to lower levels of spending by oil and gas companies as previously noted, coupled with excess rig availability in the region.  Contract drilling expense increased by $6.0 million, or 5%, as compared to the prior year period, primarily due to a $12.2 million loss on impairment of ENSCO I, our only barge rig, partially offset by a decline in payroll expense.  Depreciation expense was comparable to the prior year period.

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    Europe and Africa

 Europe and Africa revenues for the quarter ended June 30, 2010 declined by $102.5 million, or 58%, as compared to the prior year quarter. The decline in revenues was primarily due to a 43% decline in average day rates and a decline in utilization to 63% from 87% in the prior year quarter, due to lower levels of spending by oil and gas companies in response to the current economic environment.  Contract drilling expense declined by $1.6 million, or 3%, as compared to the prior year quarter, due to a decline i n payroll and repair and maintenance expense.  Depreciation expense increased by 8% due to the ENSCO 100 capital enhancement project completed during 2009 and depreciation on minor upgrades and improvements to our Europe and Africa fleet completed during 2009 and the first half of 2010.

 Europe and Africa revenues for the six-month period ended June 30, 2010 declined by $211.3 million, or 57%, as compared to the prior year period. The decline was primarily due to a decline in utilization to 66% from 93% in the comparable prior year period and a 39% decline in average day rates, due to lower levels of spending by oil and gas companies as previously noted.  Contract drilling expense declined by $8.0 million, or 8%, as compared to the prior year period, due to a decline in payroll and repair an d maintenance expense.  Depreciation expense increased by 8% due to the ENSCO 100 capital enhancement project completed during 2009 and depreciation on minor upgrades and improvements to our Europe and Africa fleet completed during 2009 and the first half of 2010.

    North and South America

 North and South America revenues for the quarter ended June 30, 2010 declined by $15.8 million, or 15%, as compared to the prior year quarter. The decline was primarily due to a 30% decline in average day rates, partially offset by an increase in utilization to 87% from 72% in the prior year quarter. The increase in utilization resulted primarily from the reduced supply of available jackup rigs in the Gulf of Mexico, including the mobilization of five of our jackup rigs to Mexico during 2009, and lower marke t day rates in the region.  Contract drilling expense increased by $3.2 million, or 8%, as compared to the prior year quarter, due to the impact of increased utilization.  Depreciation expense increased by 5% due to capital enhancement projects completed during 2009 on our jackup rigs contracted with PEMEX.

 North and South America revenues for the six-month period ended June 30, 2010 declined by $16.3 million, or 8%, as compared to the prior year period. The decline was primarily due to a 28% decline in average day rates, partially offset by an increase in utilization to 86% from 70% in the comparable prior year period. The increase in utilization resulted from the reduced supply of available jackup rigs in the Gulf of Mexico, including the mobilization of five of our jackup rigs to Mexico during 2009, and  ;lower market day rates in the region.  Contract drilling expense increased by $3.0 million, or 4%, as compared to the prior year period, due to the impact of increased utilization, partially offset by a decline in repair and maintenance expense. Depreciation expense increased by 5% due to capital enhancement projects completed during 2009 on our jackup rigs contracted with PEMEX.

    Other

 General and administrative expense for the three-month and six-month periods ended June 30, 2010 increased by $6.0 million, or 38%, and $14.6 million, or 52%, respectively, as compared to the respective prior year periods. These increases were primarily due to increased professional fees incurred in connection with various reorganization efforts undertaken as a result of our redomestication to the U.K. in December 2009, increased share-based compensation expense and costs related to operating our new London headquarters.

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Other Income, Net

 The following summarizes other income, net, for the three-month and six-month periods ended June 30, 2010 and 2009 (in millions):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
Interest income	$   .2		$   .4		$    .3		$  1.1
Interest expense, net:
Interest expense	(5.4	)	(5.3	)	(10.4	)	(10.6	)
Capitalized interest	5.4		5.3		10.4		10.6
	--		--		--		--
Other, net	12.6		6.5		15.6		1.5
	$12.8		$ 6.9		$ 15.9		$  2.6

 Interest income for the three-month and six-month periods ended June 30, 2010 declined as compared to the respective prior year periods due to lower average interest rates, partially offset by an increase in amounts invested. Interest expense for the three-month and six-month periods ended June 30, 2010 was comparable with the respective prior year periods.

 During the quarter ended June 30, 2010, we recognized a gain of $11.4 million, net of related expenses, for a break-up fee resulting from our unsuccessful tender offer for Scorpion Offshore Ltd.  The net gain was included in other, net, for the three-month and six-month periods ended June 30, 2010.

 Our functional currency is the U.S. dollar, and a portion of the revenues earned and expenses incurred by some of our subsidiaries are denominated in currencies other than the U.S. dollar ("foreign currencies"). These transactions are remeasured in U.S. dollars based on a combination of both current and historical exchange rates. Net foreign currency exchange gains of $1.9 million and $4.0 million we re included in other, net, for the three-month and six-month periods ended June 30, 2010, respectively.   Net foreign currency exchange gains of $6.5 million and $500,000 were included in other, net, for the three-month and six-month periods ended June 30, 2009, respectively.  

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Provision for Income Taxes

 Income tax rates imposed in the tax jurisdictions in which our subsidiaries conduct operations vary, as does the tax base to which the rates are applied. In some cases, tax rates may be applicable to gross revenues, statutory or negotiated deemed profits or other bases utilized under local tax laws, rather than to net income. Our drilling rigs fr equently move from one taxing jurisdiction to another to perform contract drilling services. In some instances, the movement of drilling rigs among taxing jurisdictions will involve the transfer of ownership of the drilling rig among our subsidiaries. As a result of the frequent changes in taxing jurisdictions in which our drilling rigs are operated and/or owned, our consolidated effective income tax rate may vary substantially from one reporting period to another, depending on the relative components of our earnings generated in tax jurisdictions with higher tax rates or lower tax rates.

 Subsequent to our redomestication to the U.K. in December 2009, we reorganized our worldwide operations, which included, among other things, the transfer of ownership of several of our drilling rigs among our subsidiaries.

 Income tax expense was $19.6 million and $49.5 million for the quarters ended June 30, 2010 and 2009, respectively. The $29.9 million decline in income tax expense as compared to the prior year quarter was primarily due to reduced profitability and a decline in our consolidated effective income tax rate to 14.3% from 18.3% in the prior year quarter. The decline in our 2010 consolidated effective income tax rate as compared to the prior year quarter was primarily due to the aforementioned transfer of drilling rig ownership in connection with the reorganization of our worldwide operations, which resulted in an increase in the relative components of our earnings generated in tax jurisdictions with lower tax rates.

 Income tax expense was $51.4 million and $103.7 million for the six-month period ended June 30, 2010 and 2009, respectively. The $52.3 million decline in income tax expense as compared to the prior year period was primarily due to reduced profitability and a decline in our consolidated effective income tax rate to 15.8% from 19.2% in the comparable prior year period.   The decline in our 2010 consolidated effective income tax rate as compared to the prior year period was primarily due to the aforementioned transfer of drilling rig ownership in connection with the reorganization of our worldwide operations, which resulted in an increase in the relative components of our earnings generated in tax jurisdictions with lower tax rates.

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Discontinued Operations

    Rig Sales

 In recent years we have focused on the expansion of our ultra-deepwater semisubmersible rig fleet and high-grading our premium jackup fleet.  Accordingly, we sold jackup rig ENSCO 57 in April 2010 for $47.1 million, of which $4.7 million was received in December 2009. We recognized a pre-tax gain of $17.9 million in connection with the disposal of ENSCO 57, which was included in gain on disposal of discontinued operations, net, in our condensed consolidated statements of income for three-month and six-month periods ended June 30, 2010.  ENSCO 57 operating results were reclassified as discontinued operations in our condensed consolid ated statements of income for the three-month and six-month periods ended June 30, 2010 and 2009.  See Note 11 to our condensed consolidated financial statements for additional information on the sale of ENSCO 57.

 In March 2010, we sold jackup rigs ENSCO 50 and ENSCO 51 for an aggregate $94.7 million, of which $4.7 million was received in December 2009. We recognized an aggregate pre-tax gain of $33.9 million in connection with the disposals of ENSCO 50 and ENSCO 51, which was included in gain on disposal of discontinued operations, net, in our condensed consolidated statement of income for the six-month period ended June 30, 2010.  ENSCO 50 and ENSCO 51 operating results were reclassified as discontinued operations in our condensed cons olidated statements of income for the three-month and six-month periods ended June 30, 2010 and 2009.  See Note 11 to our condensed consolidated financial statements for additional information on the sale of ENSCO 50 and ENSCO 51.

    ENSCO 69

 From May 2007 to June 2009, ENSCO 69 was contracted to Petrosucre, a subsidiary of Petróleos de Venezuela S.A., the national oil company of Venezuela ("PDVSA"). In January 2009, we suspended drilling operations on ENSCO 69 after Petrosucre failed to satisfy its contractual obligations and meet commitments relative to the payment of past due invoices. Petrosucre then took over complete control of ENSCO 69 drilling operations utilizing Petrosucre employees and a portion of the Venezuelan rig crews we had utilized.

 On June 4, 2009, after Petrosucre's failure to satisfy its contractual payment obligations, failure to reach a mutually acceptable agreement with us and denial of our request to demobilize ENSCO 69 from Venezuela, Petrosucre advised that it would not return the rig and would continue to operate it without our consent. Petrosucre further advised that it would release ENSCO 69 after a six-month period, subject to a mutually agreed accord addressing the resolution of all remaining obligations under the ENSCO 69 drilling contract. On June 6, 2009 , we terminated our contract with Petrosucre and removed all remaining Ensco employees from the rig.

 Due to Petrosucre's failure to satisfy its contractual obligations and meet payment commitments, and in consideration of the Venezuelan government's nationalization of assets owned by international oil and gas companies and oilfield service companies, we concluded it was remote that ENSCO 69 would be returned to us by Petrosucre and operated again by Ensco. Therefore, we recorded the disposal of ENSCO 69 during the second quarter of 2009. ENSCO 69 operating results were reclassified as discontinued operations in our condensed consolidated sta tements of income for the three-month and six-month periods ended June 30, 2010 and 2009.

 In November 2009, we executed an agreement with Petrosucre to mitigate our losses and resolve issues relative to outstanding amounts owed by Petrosucre for drilling operations performed by Ensco through the date of termination of the drilling contract in June 2009 (the "agreement"). Although ENSCO 69 will continue to be fully controlled and operated by Petrosucre, the agreement requires Petrosucre to compensate us for its ongoing use of the rig.  We recognized $5.5 million and $12.4 million of pre-tax income from discontinued operations for the three-month and six-month periods ended June 30, 2010 associated with collections under the agreement.

 Although the agreement obligates Petrosucre to make additional payments for its use of the rig through June 30, 2010, the associated income was not recognized in our condensed consolidated statements of income, as collectability was not reasonably assured. There can be no assurances relative to the recovery of outstanding contract entitlements, insurance recovery and related pending litigation, the possible return of ENSCO 69 to us by Petrosucre or the imposition of customs duties in relation to the rig's ongoing presence in Venezuela. See No te 12 to our condensed consolidated financial statements for additional information on insurance and legal remedies related to ENSCO 69.

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 The following table summarizes our income (loss) from discontinued operations for the three-month and six-month periods ended June 30, 2010 and 2009 (in millions):

	Three Months Ended                June 30,				Six Months Ended             June 30,
	2010		2009		2010	2009
Revenues	$ 5.0		$ 14.3		$24.7	$ 44.2
Operating expenses	1.3		19.4		10.7	42.2
Operating income (loss) before income taxes	3.7		(5.1	)	14.0	2.0
Income tax (benefit) expense	(.8	)	3.4		3.8	3.7
Gain (loss) on disposal of discontinued operations, net	5.7		(11.8	)	34.9	(11.8	)
Income (loss) from discontinued operations	$10.2		$(20.3	)	$45.1	$(13.5	)

Fair Value Measurements

    Auction Rate Securities

 Our auction rate securities were measured at fair value as of June 30, 2010 and December 31, 2009 using significant Level 3 inputs.  As a result of continued auction failures, quoted prices for our auction rate securities did not exist as of June 30, 2010 and, accordingly, we concluded that Level 1 inputs were not available.  We used an income approach valuation model to estimate the price that would be received in exchange for our auction rate securities in an orderly transaction between market participants ("exit price") as of June 30, 2010. The exit price was derived as the weighted- average present value of expected cash flows over various periods of illiquidity, using a risk-adjusted discount rate that was based on the credit risk and liquidity risk of our auction rate securities.

 While our valuation model was based on both Level 2 (credit quality and interest rates) and Level 3 inputs, we determined that Level 3 inputs were significant to the overall fair value measurement, particularly the estimates of risk-adjusted discount rates and ranges of expected periods of illiquidity. We reviewed these inputs to our valuation model, evaluated the results and performed sensitivity analysis on key assumptions. Based on our review, we concluded that the fair value measurement of our auction rate securities as of June 30, 2010 was appropriate.

 Based on the results of our fair value measurements, we recognized net unrealized gains of $300,000 and $600,000 during the three-month and six-month periods ended June 30, 2010, included in other income, net, in our condensed consolidated statements of income. The carrying values of our auction rate securities, classified as long-term investments on our condensed consolidated balance sheets, were $45.2 million and $60.5 million as of June 30, 2010 and December 31, 2009, respectively. We anticipate realizing the $50.9 million (par value) of our auction rate securities on the b asis that we intend to hold them until they are redeemed, repurchased or sold in a market that facilitates orderly transactions.

 Auction rate securities measured at fair value using significant Level 3 inputs constituted 67% of our assets measured at fair value on a recurring basis and less than 1% of our total assets as of June 30, 2010.  See Note 9 to our condensed consolidated financial statements for additional information on our fair value measurements.

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    ENSCO I Impairment

 During the quarter ended June 30, 2010, we recorded a $12.2 million loss from the impairment of ENSCO I, the only barge rig in our fleet, which is currently cold-stacked in Singapore and is included in our Asia Pacific operating segment. The loss on impairment was included in contract drilling expense in our condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2010. The impairment resulted from the adjustment of the rig’s car rying value to its estimated fair value based on a change in our expectation that it is more-likely-than-not that the rig will be disposed of significantly before the end of its estimated useful life. ENSCO I was not classified as held-for-sale as of June 30, 2010, as a sale was not deemed probable of occurring within the next twelve months.

 We utilized an income approach valuation model to estimate the price that would be received in exchange for the rig in an orderly transaction between market participants as of June 30, 2010. The resulting exit price was derived as the present value of expected cash flows from the use and eventual disposition of the rig, using a risk-adjusted discount rate.  Level 3 inputs were significant to the overall fair value measurement o f ENSCO I, due to the limited availability of observable market data for similar assets.  We reviewed those inputs, evaluated the results and performed sensitivity analysis on key assumptions. Based on our review, we concluded that the fair value measurement of ENSCO I as of June 30, 2010 was appropriate.

 The estimated fair value of ENSCO I using significant Level 3 inputs constituted less than 1% of our total assets as of June 30, 2010. See Note 9 to our condensed consolidated financial statements for additional information on our fair value measurements.

LIQUIDITY AND CAPITAL RESOURCES

 Although our business has historically been very cyclical, we have relied on our cash flow from continuing operations to meet liquidity needs and fund the majority of our cash requirements. We have maintained a strong financial position through the disciplined and conservative use of debt. A substantial portion of our cash flow is invested in the expansion and enhancement of our fleet of drilling rigs in general and construction of our ENSCO 8500 Series® rigs in particular.

 It is likely that the impact from the BP Macondo well incident and resulting legislative, regulatory or permit requirements could result in a decline in our cash flow from operations during the second half of 2010 and beyond. However, based on $1,237.1 million of cash and cash equivalents on hand as of June 30, 2010 and our current contractual backlog, we believe our future operations and remaining obligations associated with the construction of our ENSCO 8500 Series® rigs will be funded from existing c ash and cash equivalents and future operating cash flow.

 During the six-month period ended June 30, 2010, our primary source of cash was $343.6 million generated from continuing operations and $132.4 million of proceeds from the sale of three jackup rigs.  Our primary uses of cash for the same period included $336.6 million for the construction, enhancement and other improvement of our drilling rigs, including $267.2 invested in the construction of our ENSCO 8500 Series® rigs, and $53.6 million for the payment of dividends.

 During the six-month period ended June 30, 2009, our primary source of cash was $564.5 million generated from continuing operations. Our primary uses of cash for the same period included $469.1 million for the construction, enhancement and other improvement of our drilling rigs including $328.5 million invested in the construction of our ENSCO 8500 Series® rigs.

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Cash Flow and Capital Expenditures

 Our cash flow from continuing operations and capital expenditures on continuing operations for the six-month periods ended June 30, 2010 and 2009 were as follows (in millions):

	Six Months Ended               June 30,
	2010	2009
Cash flow from continuing operations	$343.6	$564.5
Capital expenditures on continuing operations
New rig construction	$267.2	$328.5
Rig acquisition	18.6	--
Rig enhancements	5.1	88.3
Minor upgrades and improvements	45.7	52.3
	$336.6	$469.1

 Cash flow from continuing operations decreased by $220.9 million, or 39%, for the six-month period ended June 30, 2010 as compared to the prior year period. The decline resulted primarily from a $219.9 million decline in cash receipts from contract drilling services and a $43.1 million increase in cash payments related to contract drilling expenses, partially offset by a $21.5 million decline in tax payments and a $13.3 million increase in cash receipts from repurchases/redemptions of our auction rate securities.

 We continue to expand the size and quality of our drilling rig fleet. We have four ENSCO 8500 Series® ultra-deepwater semisubmersible rigs under construction with scheduled delivery dates during the fourth quarter of 2010, the second half of 2011 and the first and second half of 2012.  In addition, ENSCO 8502 was delivered in January 2010 and is scheduled to commence drilling operations under a two-year contract in August 2010 although our customer has questioned whether the moratorium/suspension and related NTLs will delay contract commencement.  We believe ENSCO 8502 is in compliance wi th contractual requirements and current applicable regulations and that the drilling contract should commence in accordance with its terms.  ENSCO 8503 is committed under a long-term drilling contract in the Gulf of Mexico and is scheduled to commence drilling operations during the first quarter of 2011.  The remaining ENSCO 8500 Series® rigs under construction currently are without contracts.

 In conjunction with our long-established strategy of high-grading our fleet by investing in newer equipment, we acquired a KFELS Super B Class design jackup rig in July 2010 with available cash for $186.0 million.  The rig, which was constructed in 2008, has been renamed ENSCO 109, and we will assume its drilling contract offshore Australia that extends through May 2011. 

 Based on our current projections, we expect capital expenditures during 2010 to include approximately $620.0 million for construction of our ENSCO 8500® Series rigs, approximately $186.0 million for the acquisition of ENSCO 109, approximately $40.0 million for rig enhancement projects and approximately $100.0 million for minor upgrades and improvements. Depending on market conditions and opportunities, we may make a dditional capital expenditures to upgrade rigs and construct or acquire additional rigs.

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Financing and Capital Resources

 Our long-term debt, total capital and long-term debt to total capital ratios as of June 30, 2010 and December 31, 2009 are summarized below (in millions, except percentages):

	June 30,   2010		December 31,         2009
Long-term debt	$   248.6		$   257.2
Total capital*	$6,016.2		$5,756.4
Long-term debt to total capital	4.1	%	4.5	%
*Total capital consists of long-term debt and Ensco shareholders' equity.

 On May 28, 2010, we entered into an amended and restated agreement (the "2010 Credit Facility") with a syndicate of banks that provides for a $700.0 million unsecured revolving credit facility for general corporate purposes. The 2010 Credit Facility has a four-year term, expiring in May 2014, and replaces our $350.0 million five-year credit agreement which was scheduled to mature in June 2010.  Advances under the 2010 Cred it Facility bear interest at LIBOR plus an applicable margin rate (currently 2.0% per annum), depending on our credit rating.  We are required to pay an annual undrawn facility fee (currently .25% per annum) on the total $700.0 million commitment, which is also based on our credit rating.  We also are required to maintain a debt to total capitalization ratio less than or equal to 50% under the 2010 Credit Facility. We have the right, subject to lender consent, to increase the commitments under the 2010 Credit Facility up to $850.0 million.  We had no amounts outstanding under the 2010 Credit Facility or the prior credit agreement as of June 30, 2010 and December 31, 2009, respectively.  We currently maintain an investment grade credit rating of Baa1 from Moody's Investor's Service and BBB+ from Standard & Poor's Ratings Service. 

 We filed a Form S-3 Registration Statement with the Securities and Exchange Commission (the "SEC") in January 2009, which provides us the ability to issue debt and/or equity securities in one or more offerings.  The registration statement was immediately effective and expires in January 2012.

 As of June 30, 2010, we had an aggregate $116.9 million outstanding under two separate bond issues guaranteed by the United States of America, acting by and through the United States Department of Transportation, Maritime Administration ("MARAD"), that require semiannual principal and interest payments. We also make semiannual interest payments on $150.0 million of 7.20% debentures due in 2027.

 The Board of Directors of ENSCO International Incorporated previously authorized the repurchase of up to $1,500.0 million of our American depositary shares ("ADSs" or "shares"), representing our Class A ordinary shares. In December 2009, the then-Board of Directors of Ensco International Limited, a predecessor of Ensco plc, continued the prior authorization and, subject to shareholder approval, authorized management to repurchase up to $562.4 million of ADSs from time to time pursuant to share repurchase agreements with two investment banks. The then-sole shareholder of Ensco International Limited approved such share repurchase agreements for a five-year term.  No shares were repurchased under the share repurchase programs during the six-month period ended June 30, 2010. Although $562.4 million remained available for repurchase as of June 30, 2010, we will not repurchase any shares under our share repurchase program without further consultation with and approval by the Board of Directors of Ensco plc.

Liquidity

 Our liquidity position as of June 30, 2010 and December 31, 2009 is summarized in the table below (in millions, except ratios):

	June 30,     2010	December 31,         2009
Cash and cash equivalents	$1,237.1	$1,141.4
Working capital	$1,271.2	$1,167.9
Current ratio	4.0	3.4

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 We expect to fund our short-term liquidity needs, including contractual obligations and anticipated capital expenditures, as well as any dividends, stock repurchases or working capital requirements, from our cash and cash equivalents and operating cash flow. We expect to fund our long-term liquidity needs, including contractual obligations, anticipated capital expenditures and dividends, from our cash and cash equivalents, investments, operating cash flow and, if necessary, funds borrowed under our credit facility or other future financing arrangements.

 Based on our $1,237.1 million of cash and cash equivalents as of June 30, 2010 and our current contractual backlog, we believe our remaining $909.7 million of contractual obligations associated with the construction of our ENSCO 8500 Series® rigs will be funded from existing cash and cash equivalents and future operating cash flow. We may decide to access debt markets to raise additional capital or increase liquidity as necessary.

Effects of Climate Change and Climate Change Regulation

 Greenhouse gas emissions have increasingly become the subject of international, national, regional, state and local attention. Cap and trade initiatives to limit greenhouse gas emissions have been introduced in the European Union. Similarly, numerous bills related to climate change have been introduced in the U.S. Congress, which could adversely impact most industries. In addition, future regulation of greenhouse gas could occur pursuant to future treaty obligations, statutory or regulatory changes or new climate change legislation in the jurisdictions in which we operate. It is uncertain whether any of these initiatives will be implemented. However, based on published media reports, we believe that it is not reasonably likely that the current proposed initiatives in the U.S. will be implemented without substantial modification. If such initiatives are implemented, we do not believe that such initiatives would have a direct, material adverse effect on our operating costs.

 Restrictions on greenhouse gas emissions could have an indirect effect in those industries that use significant amounts of petroleum products, which could potentially result in a reduction in demand for petroleum products and, consequently, our offshore contract drilling services. We are currently unable to predict the manner or extent of any such effect. Furthermore, one of the long-term physical effects of climate change may be an increase in the severity and frequency of adverse weather conditions, such as hurricanes, which may increase our insurance costs or risk retention, limit insurance availability or reduce the areas in which, or the number of days during which, our customers would contract for our drilling rigs in general and in the Gulf of Mexico in particular. We are currently unable to predict the manner or extent of any such effect.

MARKET RISK

    Derivatives

 We use derivatives to reduce our exposure to various market risks, primarily foreign currency exchange rate risk. Our functional currency is the U.S. dollar. As is customary in the oil and gas industry, a majority of our revenues are denominated in U.S. dollars, however, a portion of the expenses incurred by some of our subsidiaries are denominated in currencies other than the U.S. dollar.  We maintain a foreign currency exchange rate risk management strategy that utilizes derivatives to reduce our exposure to unanticipated fluctuations in earnings and cash flows caused by changes in foreign currency exchange rates. We occasionally employ an interest r ate risk management strategy that utilizes derivative instruments to minimize or eliminate unanticipated fluctuations in earnings and cash flows arising from changes in, and volatility of, interest rates.

 We utilize derivatives to hedge forecasted foreign currency denominated transactions, primarily to reduce our exposure to foreign currency exchange rate risk associated with the portion of our remaining ENSCO 8500 Series® construction obligations denominated in Singapore dollars and contract drilling expenses denominated in various other currencies. As of June 30, 2010, $207.6 million of the aggregate remaining contractual obligations associated with our ENSCO 8500 Series® construction projects was denominated in Singapore dollars, of which $155.1 million was hedged through derivatives.

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 We have net assets and liabilities denominated in numerous foreign currencies and use various methods to manage our exposure to changes in foreign currency exchange rates. We predominantly structure our drilling contracts in U.S. dollars, which significantly reduces the portion of our cash flows and assets denominated in foreign currencies. We also employ various strategies, including the use of de rivatives, to match foreign currency denominated assets with equal or near equal amounts of foreign currency denominated liabilities, thereby minimizing exposure to earnings fluctuations caused by changes in foreign currency exchange rates.

 We utilize derivatives and undertake foreign currency exchange rate hedging activities in accordance with our established policies for the management of market risk. We minimize our credit risk relating to the counterparties of our derivatives by transacting with multiple, high-quality financial institutions, thereby limiting exposure to individual counterparties, and by monitoring the financial condition of our counterparties. We do not enter into derivatives for trading or other speculative purposes. We believe that our use of derivatives and related hedging activities reduces our exposure to foreign currency exchange rate risk and interest rate risk and does not expose us to material credit risk or any other material market risk.

 As of June 30, 2010, we had derivatives outstanding to exchange an aggregate $257.0 million for various foreign currencies, including $161.5 million for Singapore dollars. If we were to incur a hypothetical 10% adverse change in foreign currency exchange rates, net unrealized losses associated with our foreign currency denominated assets and liabilities and related derivatives as of June 30, 2010 would approximate $21.4 million, including $15.4 million relate d to our Singapore dollar exposures. All of our derivatives mature during the next 15 months. See Note 4 to our condensed consolidated financial statements for additional information on our derivative instruments.

    Auction Rate Securities

 We have generated a substantial cash balance, portions of which are invested in securities that meet our requirements for quality and return. Investment of our cash exposes us to market risk. We held $50.9 million (par value) of auction rate securities with a carrying value of $45.2 million as of June 30, 2010. We intend to hold these securities until they can be redeemed by issuers, repurchased by brokerage firms or sold in a market that facilitates orderly transactions. Due to significant uncertainties related to the auction rate securities market, we will be exposed to the risk of changes in the fair value of these securities in future periods.

 To measure the fair value of our auction rate securities as of June 30, 2010, we used an income approach valuation model to estimate the price that would be received in exchange for our auction rate securities in an orderly transaction between market participants.  The resulting exit price was derived as the weighted-average present value of expected cash flows over various periods of illiquidity, using a risk-adjusted discount rate based on the credit risk and liquidity risk of our auction rate securities. If we were to incur a hypothetical 10% adverse change in the risk-adjusted discount rate and a 10% adverse change in the periods of illiquidity, the additional net unrealized losses on our auction rate securities as of June 30, 2010 would approximate $1.5 million. See Note 9 to our condensed consolidated financial statements for additional information on our auction rate securities.

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CRITICAL ACCOUNTING POLICIES

 The preparation of our consolidated financial statements and related disclosures in conformity with GAAP requires our management to make estimates, judgments and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Our significant accounting policies are included in Note 1 to the Consolidated Financial Statements for the year ended December 31, 2009 included in our Annual Report on Form 10-K filed with the SEC on February 25, 2010, as updated in the Current Report on Form 8-K dated June 8, 2010.  These policies, along with our underlying judgments and assumptions made in their application, have a significant impact on our consolidated financial statements. We identify our critical accounting policies as those that are the most pervasive and important to the portrayal of our financial position and operating results, and that require the most difficult, subjective and/or complex judgments by management regarding estimates in matters that are inherently uncertain. Our critical accounting policies are those related to property and equipment, impairment of long-lived assets and goodwill and income taxes.

    Property and Equipment

 As of June 30, 2010, the carrying value of our property and equipment totaled $4,604.8 million, which represented 67% of total assets. This carrying value reflects the application of our property and equipment accounting policies, which incorporate management's estimates, judgments and assumptions relative to the capitalized costs, useful lives and salvage values of our rigs.

 We develop and apply property and equipment accounting policies that are designed to appropriately and consistently capitalize those costs incurred to enhance, improve and extend the useful lives of our assets and expense those costs incurred to repair or maintain the existing condition or useful lives of our assets. The development and application of such policies requires estimates, judgments and assumptions by management relative to the nature of, and benefits from, expenditures on our assets . We establish property and equipment accounting policies that are designed to depreciate our assets over their estimated useful lives. The judgments and assumptions used by management in determining the useful lives of our property and equipment reflect both historical experience and expectations regarding future operations, utilization and performance of our assets. The use of different estimates, judgments and assumptions in the establishment of our property and equipment accounting policies, especially those involving the useful lives of our rigs, would likely result in materially different carrying values of assets and operating results.

 For additional information on the useful lives of our drilling rigs, including an analysis of the impact of various changes in useful life assumptions, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies and Estimates" in Part II of our Annual Report on Form 10-K for the year ended December 31, 2009, as updated in the Current Report on Form 8-K dated June 8, 2010.

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    Impairment of Long-Lived Assets and Goodwill

 We evaluate the carrying value of our property and equipment, primarily our drilling rigs, when events or changes in circumstances indicate that the carrying value of such rigs may not be recoverable. Generally, extended periods of idle time and/or inability to contract rigs at economical rates are an indication that a rig may be impaired. However, the offshore drilling industry has historically been highly cyclical, and it is not unusual for rigs to be unutilized or underutilized for significant periods of time and subsequently resume full or near full utilization when business cycles change. Likewise, during periods of supply and demand imbalance, rigs are frequently contracted at or ne ar cash break-even rates for extended periods of time until day rates increase when demand comes back into balance with supply. Impairment situations may arise with respect to specific individual rigs, groups of rigs, such as a specific type of drilling rig, or rigs in a certain geographic location. Our rigs are mobile and may generally be moved from markets with excess supply, if economically feasible. Our ultra-deepwater semisubmersible rigs and jackup rigs are suited for, and accessible to, broad and numerous markets throughout the world.

 For property and equipment used in our operations, recoverability generally is determined by comparing the carrying value of an asset to the expected undiscounted future cash flows of the asset. If the carrying value of an asset is not recoverable, the amount of impairment loss is measured as the difference between the carrying value of the asset and its estimated fair value. The determination of expected undiscounted cash flow amounts requires significant estimates, judgments and assumptions, including future utilization, day rates, expense levels and capital requirements for each of our drilling rigs, as well as cash flows generated upon disposition. Due to the inherent uncertainties associated with these estimates, we perform sensitivity analysis on key assumptions as part of our recoverability test.

 If the global economy deteriorates and/or other events or changes in circumstances indicate that the carrying value of one or more of our drilling rigs may not be recoverable, we will conclude that a triggering event has occurred and perform a recoverability test. If, at the time of the recoverability test, management's judgments and assumptions regarding future industry conditions and operations have diminished, it is reasonably possible that we would conclude that one or more of our drilling rigs are impaired.

 We test goodwill for impairment on an annual basis, or when events or changes in circumstances indicate that a potential impairment exists. The goodwill impairment test requires us to identify reporting units and estimate each unit's fair value as of the testing date. Our four operating segments represent our reporting units.  In most instances, our calculation of the fair value of our reporting units is based on estimates of future discounted cash flows to be generated by our drilling rigs, which reflect management's judgments and assumptions regarding the appropriate risk-adjusted discount rate, as well as future industry conditions and operations, including future utiliz ation, day rates, expense levels, capital requirements and terminal values for each of our drilling rigs.  Due to the inherent uncertainties associated with these estimates, we perform sensitivity analysis on key assumptions as part of our goodwill impairment test.

 If the aggregate fair value of our reporting units exceeds our market capitalization, we evaluate the reasonableness of the implied control premium which includes a comparison to implied control premiums from recent market transactions within our industry or other relevant benchmark data. To the extent that the implied control premium based on the aggregate fair value of our reporting units is not reasonable, we adjust the discount rate used in our discounted cash flow model and reduce the estimated fair values of our reporting units.

 If the estimated fair value of a reporting unit exceeds its carrying value, its goodwill is considered not impaired. If the estimated fair value of a reporting unit is less than its carrying value, we estimate the implied fair value of the reporting unit's goodwill. If the carrying amount of the reporting unit's goodwill exceeds the implied fair value of the goodwill, an impairment loss is recognized in an amount equal to such excess. In the event we dispose of drilling rig operations that constitute a business, goodwill would be allocated in the determination of gain or loss on disposal. Based on our annual goodwill impairment test performed as of December 31, 2009, there was no impairment of goodwill.

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If the global economy deteriorates and/or our expectations relative to future offshore drilling industry conditions decline, we may conclude that the fair value of one or more of our reporting units has more-likely-than-not declined below its carrying amount and perform an interim period goodwill impairment test. If, at the time of the goodwill impairment test, management's judgments and assumptions regarding future industry conditions and operations have diminished or if the market value of our shares has substantially declined, we may conclude that the goodwill of one or more of our reporting units has been impaired. It is reasonably possible that the judgments and assumptions inherent in our goodwill impairment test may change in response to future market conditions.

 Asset impairment evaluations are, by nature, highly subjective. In most instances they involve expectations of future cash flows to be generated by our drilling rigs, which reflect management's judgments and assumptions regarding future industry conditions and operations, as well as management's estimates of future utilization, day rates, expense levels and capital requirements. The estimates, judgments and assumptions used by management in the application of our asset impairment policies reflect both historical experience and an assessment of current and expected future operational, industry, market, economic and political envir onments. The use of different estimates, judgments, assumptions and expectations regarding future industry conditions and operations would likely result in materially different asset carrying values and operating results.

    Income Taxes

 We conduct operations and earn income in numerous countries and are subject to the laws of numerous tax jurisdictions. As of June 30, 2010, our condensed consolidated balance sheet included a $341.9 million net deferred income tax liability, a $60.1 million liability for income taxes currently payable and a $13.7 million liability for unrecognized tax benefits.

 The carrying values of deferred income tax assets and liabilities reflect the application of our income tax accounting policies and are based on management's estimates, judgments and assumptions regarding future operating results and levels of taxable income. Carryforwards and tax credits are assessed for realization as a reduction of future taxable income by using a more-likely-than-not determination.

 We do not provide deferred taxes on the undistributed earnings of our U.S. subsidiary and predecessor, ENSCO International Incorporated ("Ensco Delaware"), because our policy and intention is to reinvest such earnings indefinitely or until such time that they can be distributed in a tax-free manner. We do not provide deferred taxes on the undistributed earnings of Ensco Delaware's non-U.S. subsidiaries because our policy and intention is to reinvest such earnings indefinitely.

 The carrying values of liabilities for income taxes currently payable and unrecognized tax benefits are based on management's interpretation of applicable tax laws and incorporate management's estimates, judgments and assumptions regarding the use of tax planning strategies in various taxing jurisdictions. The use of different estimates, judgments and assumptions in connection with accounting for income taxes, especially those involving the deployment of tax planning strategies, may result in materially different carrying values of income tax assets and liabilities and operating results.

 We operate in many jurisdictions where tax laws relating to the offshore drilling industry are not well developed. In jurisdictions where available statutory law and regulations are incomplete or underdeveloped, we obtain professional guidance and consider existing industry practices before utilizing tax planning strategies and meeting our tax obligations.

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 Tax returns are routinely subject to audit in most jurisdictions and tax liabilities are occasionally finalized through a negotiation process. While we have not historically experienced significant adjustments to previously recognized tax assets and liabilities as a result of finalizing tax returns, there can be no assurance that significant adjustments will not arise in the future. In addition, there are several factors that could cause the future level of uncertainty relating to our tax liabilities to increase, including the following:

• The Internal Revenue Service and/or Her Majesty's Revenue and Customs may disagree with our interpretation of tax laws, treaties or regulations with respect to the redomestication.  

• During recent years, the number of tax jurisdictions in which we conduct operations has increased, and we currently anticipate that this trend will continue.  

• In order to utilize tax planning strategies and conduct operations efficiently, our subsidiaries frequently enter into transactions with affiliates that are generally subject to complex tax regulations and are frequently reviewed by tax authorities.  

• We may conduct future operations in certain tax jurisdictions where tax laws are not well developed, and it may be difficult to secure adequate professional guidance.  

• Tax laws, regulations, agreements and treaties change frequently, requiring us to modify existing tax strategies to conform to such changes.

Item 3.   Quantitative and Qualitative Disclosures About Market Risk

 Information required under Item 3. has been incorporated into "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Market Risk".

Item 4.   Controls and Procedures

 Based on their evaluation as of the end of the period covered by this Quarterly Report on Form 10-Q, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures, as defined in Rule 13a-15 under the Securities and Exchange Act of 1934 (the "Exchange Act"), are effective.

 During the fiscal quarter ended June 30, 2010, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

Item 1.   Legal Proceedings

    FCPA Internal Investigation

 Following disclosures by other offshore service companies announcing internal investigations involving the legality of amounts paid to and by customs brokers in connection with temporary importation of rigs and vessels into Nigeria, the Audit Committee of our Board of Directors and management commenced an internal investigation in July 2007. The investigation initially focused on our payments to customs brokers relating to the temporary importation of ENSCO 100, our only rig that operated offshore Nigeria during the pertinent period.

 As is customary for companies operating offshore Nigeria, we had engaged independent customs brokers to process customs clearance of routine shipments of equipment, materials and supplies and to process the ENSCO 100 temporary importation permits, extensions and renewals. One or more of the customs brokers that our subsidiary in Nigeria used to obtain the ENSCO 100 temporary import permits, extensions and renewals also provided this service to other offshore service companies that have undertaken Foreign Corrupt Practices Act ("FCPA") compliance internal investigations.

 The principal purpose of our investigation was to determine whether any of the payments made to or by our customs brokers were inappropriate under the anti-bribery provisions of the FCPA or whether any violations of the recordkeeping or internal accounting control provisions of the FCPA occurred. Our Audit Committee engaged a Washington, D.C. law firm with significant experience in investigating and advising upon FCPA matters to assist in the internal investigation.

 Following notification to the Audit Committee and to KPMG LLP, our independent registered public accounting firm, in consultation with the Audit Committee's external legal counsel, we voluntarily notified the United States Department of Justice and SEC that we had commenced an internal investigation. We expressed our intention to cooperate with both agencies, comply with their directives and fully disclose the results of the investigation. The internal investigation process has involved extensive reviews of documents and records, as well as production to the authorities, and interviews of relevant personnel. In addition to the temporary importation of ENSCO 100, the investigation has examined our customs clearance of routine shipments and immigration activities in Nigeria.

 Our internal investigation has essentially been concluded. Discussions were held with the authorities to review the results of the investigation and discuss associated matters during 2009 and the first half of 2010.  On May 24, 2010, we received notification from the SEC Division of Enforcement advising that it does not intend to recommend any enforcement actions.  We expect to receive a determination by the United States Department of Justice in the near-term. 

 Although we believe the United States Department of Justice will take into account our voluntary disclosure, our cooperation with the agency and the remediation and compliance enhancement activities that are underway, we are unable to predict the ultimate disposition of this matter, whether we will be charged with violation of the anti-bribery, recordkeeping or internal accounting control provisions of the FCPA or whether the scope of the investigation will be extended to other issues in Nigeria or to other countries. We also are unable to predict what potential corrective measures, fines, sanctions or other remedies, if any, the United States Department of Justice may seek against us or any of our employees.

 In November 2008, our Board of Directors approved enhanced FCPA compliance recommendations issued by the Audit Committee's external legal counsel, and the Company embarked upon an enhanced compliance initiative that included appointment of a Chief Compliance Officer and a Director - Corporate Compliance. We engaged consultants to assist us in implementing the compliance recommendations approved by our Board of Directors, which include an enhanced compliance policy, increased training and testing, prescribed contractual provisions for our service providers that interface with foreign government officials, due diligence for the selection of such service provi ders and an increased Company-wide awareness initiative that includes periodic issuance of FCPA Alerts.

 Since ENSCO 100 completed its contract commitment and departed Nigeria in August 2007, this matter is not expected to have a material effect on or disrupt our current operations. As noted above, we are unable to predict the outcome of this matter or estimate the extent to which we may be exposed to any resulting potential liability, sanctions or significant additional expense.

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    ENSCO 74 Loss

 In September 2008, ENSCO 74 was lost as a result of Hurricane Ike in the Gulf of Mexico. Portions of its legs remained underwater adjacent to the customer's platform, and we conducted extensive aerial and sonar reconnaissance but did not locate the rig hull. The rig was a total loss, as defined under the terms of our insurance policies.

 In March 2009, the sunken rig hull of ENSCO 74 was located approximately 95 miles from the original drilling location when it was struck by the oil tanker SKS Satilla. Following discovery of the sunken rig hull, we removed the accessible hydrocarbons onboard the rig and began planning for removal of the wreckage. As an interim measure, the wreckage was appropriately marked, and the U.S. Coast Guard issued a Notice to Mariners. We recently commenced removal of the hull wreckage and related debris.

 On March 17, 2009, we received notice from legal counsel representing certain underwriters in a subrogation claim alleging that ENSCO 74 caused a pipeline to rupture during Hurricane Ike. On September 4, 2009, High Island Offshore System, LLC, commenced civil litigation against us in the U.S. District Court for the Southern District of Texas seeking damages for the cost of repairs and business interruption in excess of $26.0 million. Based on information currently available, primarily the adequacy of available defenses, we have not concluded that it is probable that a liability exists with respect to this matter.

 On March 18, 2009, SKS OBO & Tankers AS and Kristen Gehard Jebsen Skipsrederi AS, the owner and manager of the SKS Satilla, commenced civil litigation against us in the U.S. District Court for the Southern District of Texas seeking monetary damages of $10.0 million for losses incurred when the tanker struck the sunken hull of ENSCO 74. Based on information currently available, primarily the adequacy of available defenses, we have not concluded that it is probable a liability exists with respect to this matter.

 On September 18, 2009, Sea Robin Pipeline Company, LLC, commenced civil litigation against us in the Fifteenth Judicial Court for the Parish of Lafayette and in the Nineteenth Judicial Court for the Parish of Baton Rouge, State of Louisiana seeking unspecified damages in relation to the cost of repairing damage to the pipeline, loss of revenues, survey and other damages. Based on information currently available, we have concluded that it is remote that a liability exists with respect to this matter.

 We filed a petition for exoneration or limitation of liability under U.S. admiralty and maritime law in the U.S. District Court for the Southern District of Texas on September 2, 2009. The petition seeks exoneration from or limitation of liability for any and all injury, loss or damage caused, occasioned or occurred in relation to the ENSCO 74 loss in September 2008. Claims have been presented in the exoneration/limitation proceedings by the owners of the SKS Satilla tanker and the High Island and Sea Robin pipelines. The owners of two other subsea pipelines have also presented claims in the exoneration/limitation of liability proceedings. The claims were filed on behalf of Stingray Pipeline Company, LLC, and Tennessee Gas Pipeline seeking monetary damages incurred by reason of damage to pipelines allegedly caused by ENSCO 74 during Hurricane Ike. The Stingray claim is in the amount of $14.0 million, and the Tennessee Gas Pipeline claim is for unspecified damages. Based on information currently available, we have concluded that it is remote that liabilities exist with respect to these matters.

 We have liability insurance policies that provide coverage for claims such as the tanker and pipeline claims as well as removal of wreckage and debris in excess of the property insurance policy sublimit, subject to a $10.0 million per occurrence self-insured retention for third-party claims and an annual aggregate limit of $500.0 million. We believe all liabilities associated with the ENSCO 74 loss during Hurricane Ike resulted from a single occurrence under the terms of the applicable insurance policies. However, legal counsel for certain li ability underwriters have asserted that the liability claims arise from separate occurrences. In the event of multiple occurrences, the self-insured retention is $15.0 million for two occurrences and $1.0 million for each occurrence thereafter.

 The exoneration/limitation proceedings currently include the SKS Satilla claim and the four pipeline claims described above, which effectively supersedes their prior civil litigation filings. The matter is scheduled for trial in September 2011. Although we do not expect final disposition of the claims associated with the ENSCO 74 loss to have a material adverse effect upon our financial position, operating results or cash flows, there can be no assurances as to the ultimate outcome.

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ENSCO 69

 We have filed an insurance claim under our package policy, which includes coverage for certain political risks, and are evaluating legal remedies against Petrosucre for contractual and other ENSCO 69 related damages. ENSCO 69 has an insured value of $65.0 million under our package policy, subject to a $10.0 million deductible.

 By letter dated September 30, 2009, legal counsel acting for the package policy underwriters denied coverage under the package policy and reserved rights. On March 15, 2010, underwriters commenced litigation in the U.K. High Court of Justice, Commercial Court, for purposes of enforcing mediation under the disputes clause of our package policy and precluding us from pursuing litigation in the United States. On that date, we commenced litigation styled ENSCO International Incorporated vs. Certain Underwriters at Lloyds, et a l, in the District Court, Dallas County, Texas to recover on our political risk package policy claim. Our lawsuit seeks recovery under the policy for the loss of ENSCO 69 and includes claims for wrongful denial of coverage, breach of contract, breach of the Texas insurance code, failure to timely respond to the claim and bad faith. Our lawsuit seeks actual damages in the amount of $55.0 million (insured value of $65.0 million less a $10.0 million deductible), punitive damages and attorneys' fees.

 On April 26, 2010, we obtained a temporary restraining order from the Texas Court that effectively prohibits the insurance underwriters from pursuing litigation they filed in the U.K.  These proceedings are in an early stage and there can be no assurances as to the ultimate outcome. See Note 11 to our condensed consolidated financial statements for additional information on ENSCO 69.

    ENSCO 29 Wreck Removal

 A portion of the ENSCO 29 platform drilling rig was lost over the side of a customer's platform as a result of Hurricane Katrina during 2005. Although beneficial ownership of ENSCO 29 was transferred to our insurance underwriters when the rig was determined to be a total loss, management believes we may be legally required to remove ENSCO 29 wreckage and debris from the seabed and currently estimates the removal cost to range from $5.0 million to $15.0 million. Our property insurance policies include coverage for ENSCO 29 wreckage and debris removal costs up to $3.8 million. We also have liabi lity insurance policies that provide specified coverage for wreckage and debris removal costs in excess of the $3.8 million coverage provided under our property insurance policies.

 Our liability insurance underwriters have issued letters reserving rights and effectively denying coverage by questioning the applicability of coverage for the potential ENSCO 29 wreckage and debris removal costs. During 2007, we commenced litigation in the Texas District Court of Dallas County against certain underwriters at Lloyd's of London and other insurance companies, Bryan Johnson and BC Johnson Associates, LLC (collectively "the Underwriters") alleging breach of contract, wrongful denial, bad faith and other claims which seek a declaration that removal of wreckage and debris is covered unde r our liability insurance, monetary damages, attorneys' fees and other remedies. The matter is scheduled for trial in August 2010.

 While we anticipate that any ENSCO 29 wreckage and debris removal costs incurred will be largely or fully covered by insurance, a $1.2 million provision, representing the portion of the $5.0 million low end of the range of estimated removal cost we believe is subject to liability insurance coverage, was recognized during 2006.

    Asbestos Litigation

 During 2004, we and certain current and former subsidiaries were named as defendants, along with numerous other third-party companies as co-defendants, in three multi-party lawsuits filed in the Circuit Courts of Jones County (Second Judicial District) and Jasper County (First Judicial District), Mississippi. The lawsuits sought an unspecified amount of monetary damages on behalf of individuals alleging personal injury or death, primarily under the Jones Act, purportedly resulting from exposure to asbestos on drilling rigs and associated facilities during the period 1965 through 1986.

 In compliance with the Mississippi Rules of Civil Procedure, the individual claimants in the original multi-party lawsuits whose claims were not dismissed were ordered to file either new or amended single plaintiff complaints naming the specific defendant(s) agai nst whom they intended to pursue claims. As a result, out of more than 600 initial multi-party claims, we have been named as a defendant by 65 individual plaintiffs. Of these claims, 62 claims or lawsuits are pending in Mississippi state courts and three are pending in the U.S. District Court as a result of their removal from state court.

 To date, written discovery and plaintiff depositions have taken place in eight cases involving us. While several cases have been selected for trial during 2010 and 2011, none of the cases pending against us in Mississippi state court are included within those selected cases.

 The three cases removed from state court have been assigned to the Multi-District Litigation 875, which is currently before the U.S. District Court for the Eastern District of Pennsylvania. Although the Houston law firm representing these three plaintiffs filed a Motion to Remand, seeking to bring the cases back to Mississippi state court, t he U.S. District Court denied the plaintiffs' motion by order dated December 10, 2009.

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 We intend to vigorously defend against these claims and have filed responsive pleadings preserving all defenses and challenges to jurisdiction and venue. However, discovery is still ongoing and, therefore, available information regarding the nature of all pending claims is limited. At present, we cannot reasonably determine how many of the claimants may have valid claims under the Jones Act or estimate a range of potential liability exposure, if any.

 In addition to the pending cases in Mississippi, we have two other asbestos or lung injury claims pending against us in litigation in other jurisdictions. Although we do not expect the final disposition of the Mississippi and other asbestos or lung injury lawsuits to have a material adverse effect upon our financial position, operating results or cash flows, there can be no assurances as to the ultimate outcome of the lawsuits.

    Other Matters

 On July 9, 2010, Ensco Offshore Company, a subsidiary of Ensco plc filed suit in the U.S. District Court for the Eastern District of Louisiana in New Orleans against the U.S. Department of the Interior, the U.S. Bureau of Ocean Energy Management, Regulation and Enforcement and other defendants seeking a declaration that the defendants violated the U.S. Administrative Procedures Act, the Outer Continental Shelf Lands Act and other applicable laws by imposing a six-month deepwater drilling moratorium in the U.S. Gulf of Mexico, by imposing new substantive safety and certification requirements for both shallow-water and deepwater drilling in the U.S. Gulf of Mexico and by unreasonably delaying approval of applications to drill in both shallow-water and deepwater areas of the U.S. Gulf of Mexico.  The complaint was amended on July 20, 2010 to address the actions taken by the U.S. Department of the Interior on July 12, 2010 to impose a second moratorium/suspension that generally applies to deepwater drilling in the U.S. Gulf of Mexico and documentary and permitting requirements with respect to both shallow-water and deepwater development and production drilling and related activities in the U.S. Gulf of Mexico that lack proper legislative, regulatory or procedural authorization.  The lawsuit c ontinues to seek a more well-defined regulatory process for instituting new safety measures and operational and permitting requirements for U.S. Gulf of Mexico shallow-water and deepwater offshore drilling so as to comply with the U.S. Administrative Procedures Act, the Outer Continental Shelf Lands Act and other applicable laws.

 During 2009, we filed arbitration claims with the Financial Industry Regulatory Authority ("FINRA") alleging fraud, conflict of interest and breach of contract against Citigroup Global Markets, Inc. and Merrill Lynch, Pierce, Fenner & Smith, Inc. and breach of contract against Jefferies & Company, Inc. and Oppenheimer & Co., Inc. in connection with the sale of certain auction rate securities to us in the aggregate principal amount of $50.9 million.  These pro ceedings are in the discovery stage and there can be no assurances as to the ultimate outcome.

 In addition to the foregoing, we are named defendants or parties in certain other lawsuits, claims or proceedings incidental to our business and are involved from time to time as parties to governmental investigations or proceedings, including matters related to taxation, arising in the ordinary course of business. Although the outcome of such lawsuits or other proceedings cannot be predicted with certainty and the amount of any liability that could arise with respect to such lawsuits or other proceedings cannot be predicted accurately, we do not expect these matters to have a material adverse effect on our financial position, operating results or cash flows.

Item 1A.   Risk Factors

 There are numerous factors that affect our business and results of operations, many of which are beyond our control. In addition to information set forth in this Quarterly Report, you should carefully read and consider "Item 1A. Risk Factors" in Part I and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II of our Annual Report on Form 10-K for the year ended December 31, 2009, as updated in the Current Report on Form 8-K dated June 8, 2010, which contains d escriptions of significant factors that might cause the actual results of operations in future periods to differ materially from those currently anticipated or expected. Except as set forth below, there have been no material changes from the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2009.

OUR OFFSHORE DRILLING OPERATIONS COULD BE ADVERSELY IMPACTED BY THE BP MACONDO WELL INCIDENT AND THE RESULTING CHANGES IN REGULATION OF OFFSHORE OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITY.

 In May 2010, the U.S. Department of Interior implemented a six-month moratorium/suspension on certain drilling activities in water depths greater than 500 feet in the U.S. Gulf of Mexico in response to the BP Macondo well incident. The U.S. Department of Interior subsequently issued NTLs implementing additional safety and certification requirements applicable to dril ling activities in the U.S. Gulf of Mexico, imposed additional requirements with respect to development and production activities in the U.S. Gulf of Mexico and has delayed the approval of applications to drill in both deepwater and shallow-water areas. On June 22, 2010, the U.S. District Court for the Eastern District of Louisiana granted a temporary injunction which immediately prohibited enforcement of the moratorium/suspension.  On July 12, 2010, the U.S. Department of Interior issued a revised moratorium/suspension on drilling in the U.S. Gulf of Mexico that generally applies to mobile offshore drilling units that utilize subsea blowout prevention equipment required for deepwater drilling operations.

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 Certain of our ultra-deepwater semisubmersible rigs currently contracted in the U.S. Gulf of Mexico are affected by the drilling moratorium/suspension imposed by the U.S. Department of Interior in response to the BP Macondo well incident. This moratorium/suspension and related  ;NTLs are being challenged in litigation by Ensco and others.  The operations of certain of our jackup rigs not expressly covered by the moratorium/suspension are being delayed due to the requirements of the NTLs and the drilling permit approval process.   Current or future NTLs or other directives may impact our customers' ability to obtain drilling permits and commence or continue deepwater or shallow-water operations in the U.S. Gulf of Mexico.

 Customers recently have submitted force majeure notices involving our ultra-deepwater semisubmersible (ENSCO 8500) and four of our jackup rigs (ENSCO 68, ENSCO 82, ENSCO 86 and ENSCO 87) in the U.S. Gulf of Mexico.  We have rejected all of these force majeure notices as invalid under the applicable terms o f the contract. All four jackup rigs (ENSCO 68, ENSCO 82, ENSCO 86 and ENSCO 87) currently are operating and earning full day rate.  In the event of valid force majeure circumstances, the contracts for our ultra-deepwater semisubmersible rigs currently in the U.S. Gulf of Mexico generally provide that a reduced rate applies for a specified number of days (approximately ten weeks) after which our customers have a right to terminate, subject to payment of a significant portion of the day rate for the remainder of the contract term (which, in some cases, is to be offset by other drilling work obtained during said period).  As respects our jackup rigs in the U.S. Gulf of Mexico, the contractual force majeure provisions generally provide for payment of full day rate for a specified number of days (approximately two weeks) after which our customers have a right to terminate without further payment.

 ENSCO 8502 was delivered in January 2010 and is scheduled to commence drilling operations under a two-year contract in August 2010.  Although our customer has questioned whether the new requirements of the moratorium/suspension and related NTLs will delay contract commencement, we believe ENSCO 8502 is in compl iance with contractual requirements and current applicable regulations and that the drilling contract should commence in accordance with its terms.

 We have filed suit in the U.S. District Court for the Eastern District of Louisiana to seek relief from these actions which we believe violate the U.S. Administrative Procedure Act, the Outer Continental Shelf Lands Act and other applicable laws.  We are not able to predict the outcome of these legal proceedings, whether enforcement of the moratorium/suspension and other related restrictions and delays will be enjoined, or whether the U.S. Department of Interior w ill seek to implement additional restrictions on or prohibitions of drilling activities in the U.S. Gulf of Mexico.  We have 10 rigs under contract in the U.S. Gulf of Mexico, including three ultra-deepwater semisubmersible rigs.  Our customers may seek to move rigs to locations outside of the U.S. Gulf of Mexico, perform activities permitted under the moratorium/suspension and the enhanced safety requirements or attempt to terminate our contracts pursuant to their respective force majeure or other provisions.

 At this time, we cannot predict the impact of the BP Macondo well incident and resulting changes in the regulation of offshore oil and gas exploration and development activity on our operations or contracts or what actions may be taken by our customers, other industry participants or the U.S. or other governments in response to the incident.  Future legislative or regulat ory enactments may impose new requirements for well control and blowout prevention equipment that could increase our costs and cause delays in our operations due to unavailability of associated equipment.

 A prolonged suspension of drilling activity in the U.S. Gulf of Mexico and associated new legislation or regulations in the U.S. or elsewhere could materially adversely affect our financial condition, operating results or cash flows.

COMPLIANCE WITH OR BREACH OF ENVIRONMENTAL LAWS CAN BE COSTLY AND COULD LIMIT OUR OPERATIONS.

 Our operations are subject to laws and regulations controlling the discharge of materials into the environment, pollution, contamination and hazardous waste disposal or otherwise relating to the protection of the environment. Environmental laws and regulations specifically applicable to our business activities could impose significant liability on us for damages, clean-up costs, fines and penalties in the event of oil spills or similar discharges of pollutants or contaminants into the environment or improper disposal of hazardous waste generated in the course of our operations. To date, such laws and regulations have not had a material adverse effect on our operating results, and we have not experienced an accident that has exposed us to material liability for discharges of pollutants into the environment.  However, the legislative and regulatory response to the BP Macondo well incident could substantially increase our customers' liabilities in respect of oil spills and also could increase our liabilities.  In addition to potential increased liabilities, such legislative or regulatory action could impose increased financial, insurance or other requirements that may adversely impact the entire offshore drilling industry.

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 The International Convention on Oil Pollution Preparedness, Response and Cooperation, the U.K. Merchant Shipping Act 1995, the U.K. Merchant Shipping (Oil Pollution Preparedness, Response and Cooperation Convention) Regulations 1998 and other related legislation and regulations and the Oil Pollution Act of 1990 ("OPA 90") and other U.S. federal statutes applicable to us and our operations, as well as similar statutes in Texas, Louisiana, other coastal states and other non-U.S. jurisdictions, address oil spill prevention and control and significantly expand liability, fine and penalty exposure across many segments of the oil and gas industry. Such statutes and related reg ulations impose a variety of obligations on us related to the prevention of oil spills, disposal of waste and liability for resulting damages. For instance, OPA 90 imposes strict and, with limited exceptions, joint and several liability upon each responsible party for oil removal costs as well as a variety of fines, penalties and damages. Failure to comply with these statutes and regulations, including OPA 90, may subject us to civil or criminal enforcement action, which may not be covered by contractual indemnification or insurance and could have a material adverse effect on our financial position, operating results and cash flows.

 Events in recent years, including the BP Macondo well incident, have heightened governmental and environmental concerns about the oil and gas industry. From time to time, legislative proposals have been introduced that would materially limit or prohibit offshore drilling in certain areas.  We are adversely affected by moratoria on drilling in certain areas of the Gulf of Mexico and elsewhere, including the recent moratorium/suspension in the U.S. Gulf of Mexico, restrictions on development and production activities in the U.S. Gulf of Mexico and associated NTLs that have and may further impact our operations.  If new laws are enacted or other government action is taken that restrict or prohibit offshore drilling in our principal areas of operation or impose environmental protection requirements that materially increase the liabilities, financial requirements or operating or equipment costs associated with offshore drilling, exploration, development or production of oil and natural gas, our financial position, operating results and cash flows could be materially adversely affected.

THE POTENTIAL FOR GULF OF MEXICO HURRICANE RELATED WINDSTORM DAMAGE OR LIABILITIES COULD RESULT IN UNINSURED LOSSES AND MAY CAUSE US TO ALTER OUR OPERATING PROCEDURES DURING HURRICANE SEASON, WHICH COULD ADVERSELY AFFECT OUR BUSINESS.

 Certain areas in and near the Gulf of Mexico experience hurricanes and other extreme weather conditions on a relatively frequent basis. Some of our drilling rigs in the Gulf of Mexico are located in areas that could cause them to be susceptible to damage and/or total loss by these storms, and we have a larger concentration of jackup rigs in the Gulf of Mexico than most of our competi tors. We currently have eight jackup rigs and three ultra-deepwater semisubmersible rigs in the Gulf of Mexico. Damage caused by high winds and turbulent seas could result in rig loss or damage, termination of drilling contracts on lost or severely damaged rigs or curtailment of operations on damaged drilling rigs with reduced or suspended day rates for significant periods of time until the damage can be repaired. Moreover, even if our drilling rigs are not directly damaged by such storms, we may experience disruptions in our operations due to damage to our customers' platforms and other related facilities in the area. Our drilling operations in the Gulf of Mexico have been impacted by hurricanes, including the total loss of one jackup rig during 2004, one platform rig during 2005 and one jackup rig during 2008, with associated loss of contract revenues and potential liabilities.

 Insurance companies incurred substantial losses in the offshore drilling, exploration and production industries as a consequence of hurricanes that occurred in the Gulf of Mexico during 2004, 2005 and 2008. Accordingly, insurance companies have substantially reduced the nature and amount of insurance coverage available for losses arising from named tropical storm or hurricane damage in the Gulf of Mexico ("windstorm damage") and have dramatically increased the cost of available windstorm coverage. The tight insurance market not only applies to coverage related to Gulf of Mexico windstorm damage or loss of our drilling rigs, but also impacts coverage for potential liabilities to third parties associated with property damage, personal injury or death and environmental liabilities as well as coverage for removal of wreckage and debris associated with hurricane losses. We have no assurance that the tight insurance market for windstorm damage, liabilities and removal of wreckage and debris will not continue into the foreseeable future.

 Upon renewal of our annual insurance policies effective July 1, 2010, we obtained $450.0 million of annual coverage for ultra-deepwater semisubmersible rig hull and machinery losses arising from Gulf of Mexico windstorm damage with a $50.0 million per occurrence self-insured retention (deductible). However, due to the significant premium, high self-insured retention and limited coverage, we decided not to purchase windstorm insurance for our jackup rigs remaining in the Gulf of Mexico. Accordingly, we have retained the risk for loss or damage of our eight jackup rigs remaining in the Gulf of Mexico arising out of windstorm damage.

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 Our current liability insurance policies only provide coverage for Gulf of Mexico windstorm exposures for removal of wreckage and debris in excess of $50.0 million per occurrence as respects both our jackup and ultra-deepwater semisubmersible rig operations and have an annual aggregate limit of $450.0 million. Our limited windstorm insurance coverage exposes us to a significant level of risk due to jackup rig damage or loss related to severe weather conditions caused by Gulf of Mexico hurricanes.

 We have established operational procedures designed to mitigate risk to our jackup rigs in the Gulf of Mexico during hurricane season. In addition to procedures designed to better secure the drilling package on jackup rigs, improve jackup leg stability and increase the air gap to position the hull above waves, our procedures involve analysis of prospective drilling locations, which may include enhanced bottom surveys. These procedures may result in a decision to decline to operate on a customer designated location during hurricane season notwithstanding that the location, water de pth and other standard operating conditions are within a rig's normal operating range. Our procedures and the associated regulatory requirements addressing Mobile Offshore Drilling Unit operations in the Gulf of Mexico during hurricane season, coupled with our decision to retain (self-insure) certain windstorm related risks, may result in a significant reduction in the utilization of our jackup rigs in the Gulf of Mexico.

 As noted above, we have a $50.0 million per occurrence deductible for windstorm loss or damage to our ultra-deepwater semisubmersible rigs in the Gulf of Mexico and have elected not to purchase loss or damage insurance coverage for our eight jackup rigs in the area. Moreover, we have retained the risk for the first $50.0 million of liability exposure for removal of wreckage and debris resulting from windstorm related exposures associated with our rigs in the Gulf of Mexico. These and other retained exposures for property loss or damag e and wreckage and debris removal or other liabilities associated with Gulf of Mexico hurricanes could have a material adverse effect on our financial position, operating results and cash flows if we sustain significant uninsured or underinsured losses or liabilities as a result of Gulf of Mexico hurricanes.

Item 2.   Unregistered Sales of Equity Securities and Use of Proceeds

 The table below provides a summary of our repurchases of our shares during the quarter ended June 30, 2010:

Issuer Purchases of Equity Securities
Period	Total Number of Shares Purchased	Average Price Paid per   Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or     Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under Plans or Programs
April 1 - April 30	21,270	$46.91	--		$562,000,000
May 1 - May 31	11,498	39.96	--		562,000,000
June 1 - June 30	97,616	34.70	--		562,000,000
Total	130,384	$37.15	--

 During the quarter ended June 30, 2010, repurchases of our shares were primarily from employees and non-employee directors in connection with the settlement of income tax withholding obligations arising from the vesting of share awards.

 The Board of Directors of ENSCO International Incorporated previously authorized the repurchase of up to $1,500.0 million of our shares. In December 2009, the then-Board of Directors of Ensco International Limited, a predecessor of Ensco plc, continued the prior authorization and, subject to shareholder approval, authorized management to repurchase up to $562.4 million of our ADSs from time to time pursuant to share repurchase agreements with two investment banks. The then-sole shareholder of Ensco International Limited approved such share repurchase agreements for a five-year term.  No shares were repurchased under the share repurchase programs during the six-month period ended June 30, 2010. Although $562.4 million remained available for repurchase as of June 30, 2010, we will not repurchase any shares under our share repurchase program without further consultation with and approval by the Board of Directors of Ensco plc.

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Item 6.   Exhibits

   Exhibit No.

3.1	Articles of Association of Ensco International plc (incorporated by reference to Exhibit 99.1 to the Registrant's Current Report on Form 8-K filed on December 16, 2009, File No. 1-8097).
3.2	Certificate of Incorporation on Change of Name (incorporated by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K filed on April 1, 2010, File No. 1-8097).
4.1	Form of American Depositary Receipt for American Depositary Shares representing Deposited Class A Ordinary Shares of Ensco plc (incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on April 1, 2010, File No. 1-8097).
10.1	Second Amended and Restated Credit Agreement, dated as of 28 May 2010, among Ensco plc, ENSCO International Incorporated, ENSCO Universal Limited, and ENSCO Offshore International Company, as Borrowers, Ensco plc, ENSCO Global Limited, and ENSCO International Incorporated, as Guarantors, the Banks named therein, as Banks, Citibank, N.A., as Administrative Agent, Wells Fargo Bank, National Association and DnB NOR Bank ASA, as Syndication Agents, and Wells Fargo Bank, National Association, Citibank, N.A. and DnB NOR Bank ASA, each as an Issuing Bank (incorporated by reference to Exhibit 10.1 of the Registrant's Curr ent Report on Form 8-K filed on June 3, 2010, File No. 1-8097).
10.2	Second Amended and Restated Guaranty, dated as of 28 May 2010, made by Ensco plc, ENSCO Global Limited, and ENSCO International Incorporated, as Guarantors, in favor of Citibank, N.A., as Administrative Agent under the Credit Agreement (incorporated by reference to Exhibit 10.2 of the Registrant's Current Report on Form 8-K filed on June 3, 2010, File No. 1-8097).
*15.1	Letter regarding unaudited interim financial information.
*31.1	Certification of the Chief Executive Officer of Registrant Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	Certification of the Chief Financial Officer of Registrant Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
**32.1	Certification of the Chief Executive Officer of Registrant Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
**32.2	Certification of the Chief Financial Officer of Registrant Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
**101.INS	XBRL Instance Document
**101.SCH	XBRL Taxonomy Extension Schema
**101.CAL	XBRL Taxonomy Extension Calculation Linkbase
**101.DEF	XBRL Taxonomy Extension Definition Linkbase
**101.LAB	XBRL Taxonomy Extension Label Linkbase
**101.PRE	XBRL Taxonomy Extension Presentation Linkbase

*   Filed herewith.

** Furnished herewith.

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SIGNATURES

 Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	Ensco plc
Date:  July 22, 2010	/s/ JAMES W. SWENT III          James W. Swent III Senior Vice President and Chief Financial Officer
	/s/ DAVID A. ARMOUR               David A. Armour Vice President – Finance
	/s/ DOUGLAS J. MANKO            Douglas J. Manko Controller and Assistant Secretary

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